0001123852 nspm:RegulatedNaturalGasMember 2019-04-01 2019-06-30

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

~~Commission File Number: 001-31387~~

~~(Exact name of registrant as specified in its charter)~~



~~Minnesota~~001-31387		41-1967505
(~~State or other jurisdiction of incorporation or organization)~~Commission File Number)		(I.R.S. Employer Identification No.)



Minneapolis	Minnesota	55401

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	~~55401~~
~~(Address of principal executive offices)~~Trading Symbol	~~(Zip Code)~~Name of each exchange on which registered
N/A	N/A	N/A

~~(Registrant’s telephone number, including area code)~~



Large accelerated filer¨	☐	Accelerated filer¨	☐
Non-accelerated filerx	☒	Smaller ~~reporting company~~ ¨Reporting Company	☐
~~(Do not check if smaller reporting company)~~		Emerging growth company¨	☐

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

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

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



Class		~~Outstanding at Oct. 27, 2017~~August 1, 2019
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)~~Instructions 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)~~H(2) to such Form 10-Q.



PARTI—	FINANCIAL INFORMATION

Item l1 —	Financial Statements (Unaudited)	34
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2721
Item 4 —	Controls and Procedures	3424

PART II —	OTHER INFORMATION

Item 1 —	Legal Proceedings	3424
Item 1A —	Risk Factors	3524
Item 6 —	Exhibits	3525

SIGNATURES		3626

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 onin various filings with the ~~Securities and Exchange Commission (SEC).~~SEC. This report should be read in its entirety.

~~PART I~~ — ~~FINANCIAL INFORMATION~~

ABBREVIATIONS AND INDUSTRY TERMS



Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy	Xcel Energy Inc. and its subsidiaries

Federal and State Regulatory Agencies
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOC	Minnesota Department of Commerce
EPA	Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPUC	Minnesota Public Utilities Commission
OAG	Minnesota Office of the Attorney General
SEC	Securities and Exchange Commission

Electric, Purchased Gas and Resource Adjustment Clauses
FCA	Fuel clause adjustment
GUIC	Gas utility infrastructure cost rider
RES	Renewable energy standard
TCR	Transmission cost recovery adjustment

Other
ACE	Affordable Clean Energy
APM	Alternative payment models
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
CCR	Coal combustion residuals
CCR Rule	Final rule (40 CFR 257.50 - 257.107) published by the United States Environmental Protection Agency regulating the management, storage and disposal of CCRs as nonhazardous waste
CT	Combustion turbine
DCF	Discounted cash flow
DR	Demand response
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GE	General Electric
IPP	Independent power producing entity
LIUNA	Laborers’ International Union of North America
MEC	Mankato Energy Center
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
NAV	Net asset value
NOI	Notice of inquiry
NOL	Net operating loss
O&M	Operating and maintenance
PPA	Purchased power agreement
PTC	Production tax credit
ROE	Return on equity
ROFR	Right of first refusal
ROU	Right-of-use
RTO	Regional Transmission Organization
SMMPA	Southern Minnesota Municipal Power Agency



TCJA	2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
TO	Transmission owner
VIE	Variable interest entity
Measurements
KV	Kilovolts
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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, assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including NSP-Minnesota’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2018, and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: changes in environmental laws and regulations; climate change and other weather, natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices; costs of potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; fuel costs; and employee work force and third party contractor factors.

PART I—FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in ~~thousands)~~millions)

Interest charges — includes other financing costs of

$1,845, $1,822, $5,437 and $5,325, respectively

Interest charges — includes other financing costs of

$1.8, $1.8, $3.6 and $3.6, respectively

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in ~~thousands)~~millions)

net of tax of $21, $15, $70 and $45, respectively

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in ~~thousands)~~millions)

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares

outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively

Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares

outstanding at June 30, 2019 and Dec. 31, 2018, respectively

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY (UNAUDITED) (amounts in millions, except share data)

	Common Stock Issued					Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholder’s Equity
Three Months Ended June 30, 2019 and 2018
Balance at March 31, 2018	1,000,000	$	—	$	3,600.2	$	1,947.0		$	(24.4	)	$	5,522.8
Net income						92.4						92.4
Other comprehensive income									0.2			0.2
Dividends declared to parent						(88.7		)				(88.7		)
Balance at June 30, 2018	1,000,000	$	—	$	3,600.2	$	1,950.7		$	(24.2	)	$	5,526.7

Balance at March 31, 2019	1,000,000	$	—	$	3,794.2	$	1,990.6		$	(22.9	)	$	5,761.9
Net income						95.9						95.9
Other comprehensive income									0.2			0.2
Dividends declared to parent						(95.3		)				(95.3		)
Contribution of capital by parent				4.8								4.8
Balance at June 30, 2019	1,000,000	$	—	$	3,799.0	$	1,991.2		$	(22.7	)	$	5,767.5

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY (UNAUDITED) (amounts in millions, except share data)

	Common Stock Issued					Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholder’s Equity
Six Months Ended June 30, 2019 and 2018
Balance at Dec. 31, 2017	1,000,000	$	—	$	3,580.2	$	1,919.9		$	(24.6	)	$	5,475.5
Net income						204.1						204.1
Other comprehensive income									0.4			0.4
Dividends declared to parent						(173.3		)				(173.3		)
Contribution of capital by parent				20.0								20.0
Balance at June 30, 2018	1,000,000	$	—	$	3,600.2	$	1,950.7		$	(24.2	)	$	5,526.7

Balance at Dec. 31, 2018	1,000,000	$	—	$	3,624.2	$	1,972.0		$	(23.1	)	$	5,573.1
Net income						209.1						209.1
Other comprehensive income									0.4			0.4
Dividends declared to parent						(189.9		)				(189.9		)
Contribution of capital by parent				174.8								174.8
Balance at June 30, 2019	1,000,000	$	—	$	3,799.0	$	1,991.2		$	(22.7	)	$	5,767.5

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Minnesota and its subsidiaries as of ~~Sept.~~June 30, ~~2017~~2019 and Dec. 31, ~~2016;~~2018; the results of its operations, including the components of net income and comprehensive income, and changes in stockholder’s equity for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016;~~2018; and its cash flows for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016.~~2018. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after ~~Sept.~~June 30, ~~2017~~2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, ~~2016~~2018 balance sheet information has been derived from the audited ~~2016~~2018 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, ~~2016.~~2018. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, ~~2016,~~2018, filed with the SEC on Feb. ~~24, 2017.~~22, 2019. Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.


1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, ~~2016,~~2018, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

Credit Losses— In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019, and will be applied on a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. NSP-Minnesota is currently evaluating the impact of adoption of the new standard on its consolidated financial statements.

~~Revenue Recognition~~

Recently Adopted

Leases —In ~~May 2014,~~2016, the ~~Financial Accounting Standards Board (FASB)~~FASB issued ~~Revenue from Contracts with Customers,~~ Leases, Topic ~~606 (Accounting Standards Update (ASU) No. 2014-09)~~842(ASC Topic 842), which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. NSP-Minnesota adopted the guidance on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases.

Specifically for land easement contracts, NSP-Minnesota has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842, and as a ~~new framework for~~result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate.

NSP-Minnesota also utilized the recognition of revenue. NSP-Minnesota expects its adoption will primarily result in increased disclosures regarding revenue related to arrangements with customers, as well as separate presentation of alternative revenue programs. NSP-Minnesota currently expectstransition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a ~~modified retrospective basis, which requires application to contracts with customers effective~~prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, ~~2018, with~~2019 reflect the ~~cumulative impact on contracts not yet completed as~~implementation of ~~Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.~~

~~Classification and Measurement of Financial Instruments —~~ ~~In January 2016, the FASB issued~~ ~~Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01)~~, which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reportingASC Topic 842, while prior periods beginning after Dec. 15, 2017. NSP-Minnesota expects that as a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, currently classified as available-for-sale, will continue to be ~~deferred to a regulatory asset, and that the overall impacts of the Jan. 1, 2018 adoption will not be material.~~

~~Leases —~~I~~n February 2016, the FASB issued~~ reported in accordance with Leases, Topic ~~842 (ASU No. 2016-02), which for lessees requires balance sheet~~840 (ASC Topic 840). Other than first-time recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. NSP-Minnesota has not yet fully determined the impacts of implementation. However, adoption is expected to occuroperating leases on ~~Jan. 1, 2019 utilizing the practical expedients provided by the standard. As such, agreements entered prior to Jan. 1, 2017 that are currently considered leases are expected to be recognized on the~~its consolidated balance sheet, ~~including contracts for use~~the implementation of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. NSP-Minnesota expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the new standard, but hasASC Topic 842 did not ~~yet completed its evaluation~~have a significant impact on NSP-Minnesota’s consolidated financial statements. Adoption resulted in recognition of ~~certain other contracts, including arrangements for the secondary use of assets, such as land easements.~~

~~Presentation of Net Periodic Benefit Cost —~~ ~~In March 2017, the FASB issued~~ ~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component~~approximately $0.5 billion of operating ~~income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible~~lease ROU assets and current/noncurrent operating lease liabilities. See Note 9 for capitalization. NSP-Minnesota expects that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment and that the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017.

leasing disclosures.


3.	Selected Balance Sheet Data



(Millions of Dollars)	June 30, 2019			Dec. 31, 2018
Accounts receivable, net
Accounts receivable	$	340.1		$	404.4
Less allowance for bad debts	(19.7		)	(23.5		)
	$	320.4		$	380.9



(Millions of Dollars)	June 30, 2019		Dec. 31, 2018
Inventories
Materials and supplies	$	179.2	$	176.3
Fuel	81.4		88.5
Natural gas	11.8		34.6
	$	272.4	$	299.4



(Millions of Dollars)	June 30, 2019			Dec. 31, 2018
Property, plant and equipment
Electric plant	$	17,913.4		$	17,749.3
Natural gas plant	1,493.9			1,475.5
Common and other property	826.7			803.1
Construction work in progress	835.6			615.1
Total property, plant and equipment	21,069.6			20,643.0
Less accumulated depreciation	(7,723.9		)	(7,454.8		)
Nuclear fuel	2,859.6			2,770.4
Less accumulated amortization	(2,474.9		)	(2,416.9		)
	$	13,730.4		$	13,541.7

(Thousands of Dollars) Sept. 30, 2017 Dec. 31, 2016
Accounts receivable, net
Accounts receivable $ 364,970
$ 349,449
Less allowance for bad debts (20,442 ) (19,968 )
$ 344,528
$ 329,481

(Thousands of Dollars) Sept. 30, 2017 Dec. 31, 2016
Inventories
Materials and supplies $ 216,850
$ 214,234
Fuel 91,555
97,527
Natural gas �� 41,173
33,431
$ 349,578
$ 345,192

(Thousands of Dollars) Sept. 30, 2017 Dec. 31, 2016
Property, plant and equipment, net
Electric plant $ 17,323,127
$ 17,059,993
Natural gas plant 1,340,688
1,311,235
Common and other property 803,599
710,958
Construction work in progress 508,306
509,891
Total property, plant and equipment 19,975,720
19,592,077
Less accumulated depreciation (7,015,522 ) (6,682,418 )
Nuclear fuel 2,668,586
2,571,770
Less accumulated amortization (2,268,290 ) (2,180,636 )
$ 13,360,494
$ 13,300,793


4.	~~Income Taxes~~

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

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

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

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

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

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

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

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

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

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

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

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

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

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

~~No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2017 or Dec. 31, 2016.~~


5.	~~Rate Matters~~

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 and in Note 5 to NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

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

~~Key terms:~~

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

~~Annual sales true-up with decoupling subject to a 3 percent cap;~~

~~Return on equity (ROE) of 9.2 percent and an equity ratio of 52.5 percent;~~

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

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

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

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

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

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

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

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

~~Annual Automatic Adjustment of Fuel Clause Charges —~~ In May 2017, the MPUC voted to disallow approximately $4.4 million of replacement energy costs for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction in 2015. This disallowance was recognized in the second quarter of 2017. In September 2017, the Minnesota Department of Commerce (DOC) recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages under certain circumstances. In addition, the DOC is continuing its review of nuclear costs and operations focusing on PI under the initial rate case and resource plan orders as well as the recently finalized rate case.

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

~~Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints~~ — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, and the removal of ROE adders (including those for Regional Transmission Organization (RTO) membership), effective Nov. 12, 2013.

In December 2015, an administrative law judge (ALJ) recommended the FERC approve a base ROE of 10.32 percent for the MISO TOs. The ALJ found the existing 12.38 percent ROE to be unjust and unreasonable. The recommended 10.32 percent ROE applied a FERC ROE policy adopted in a June 2014 order (Opinion 531). The FERC approved the ALJ recommended 10.32 percent base ROE in an order issued in September 2016. This ROE would be applicable for the 15 month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent, including a 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action.

In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any adder was filed with the FERC, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. In June 2016, the ALJ recommended a ROE of 9.7 percent, applying the methodology adopted by the FERC in Opinion 531. A final FERC decision on the second ROE complaint was expected later in 2017, but in April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) by opinion, vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the second ROE complaint. The MISO TOs are evaluating the impact of the D.C. Circuit ruling on the November 2013 and February 2015 ROE complaints. In September 2017, certain MISO TOs (not including NSP-Minnesota and NSP-Wisconsin) filed a motion to dismiss the second ROE complaint. The motion to dismiss is pending FERC action.

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


6.	~~Commitments and Contingencies~~

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

~~PPAs~~

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

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

~~Guarantees~~

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

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

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

~~Environmental Contingencies~~

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

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

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

~~Environmental Requirements~~

~~Water and Waste~~

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

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

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

~~Air~~

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

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

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

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

~~Legal Contingencies~~

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


7.	4. Borrowings and Other Financing Instruments

Short-Term Borrowings

NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.

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 June 30, 2019			Year Ended Dec. 31, 2018
Borrowing limit	$	250		$	250
Amount outstanding at period end	50			—
Average amount outstanding	2			17
Maximum amount outstanding	50			143
Weighted average interest rate, computed on a daily basis	2.41		%	1.96		%
Weighted average interest rate at period end	2.41			N/A

(Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2017 Year Ended Dec. 31, 2016
Borrowing limit $ 250
$ 250
Amount outstanding at period end 50
—
Average amount outstanding 50
16
Maximum amount outstanding 116
225
Weighted average interest rate, computed on a daily basis 1.11 % 0.69 %
Weighted average interest rate at period end 1.11
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 and the money pool.~~ Commercial paper outstanding for NSP-Minnesota was as follows:



(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2019			Year Ended Dec. 31, 2018
Borrowing limit	$	500		$	500
Amount outstanding at period end	194			150
Average amount outstanding	67			38
Maximum amount outstanding	226			198
Weighted average interest rate, computed on a daily basis	2.54		%	2.08		%
Weighted average interest rate at period end	2.52			2.97

(Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2017 Year Ended Dec. 31, 2016
Borrowing limit $ 500
$ 500
Amount outstanding at period end —
85
Average amount outstanding 51
73
Maximum amount outstanding 204
353
Weighted average interest rate, computed on a daily basis 1.33 % 0.65 %
Weighted average interest rate at period end N/A
0.94

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.~~June 30, ~~2017~~2019 and Dec. 31, ~~2016,~~2018, there were ~~$21~~$19 million and ~~$11~~$37 million, respectively, of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

At ~~Sept.~~June 30, ~~2017,~~2019, NSP-Minnesota had the following committed credit facility available (in millions of dollars):


Credit Facility ^(a)	Credit Facility ^(a)	Drawn ^(b)		Available		Credit Facility ^(a)	Outstanding ^(b)		Available
$	500	$	21	$	479	500	$	213	$	287

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.~~June 30, ~~2017~~2019 and Dec. 31, ~~2016.~~2018.

Bilateral Credit Agreement — In March 2019 NSP-Minnesota entered into a one year uncommitted bilateral credit agreement. This facility is limited in use to support letters of credit.

As of June 30, 2019, NSP-Minnesota’s outstanding letters of credit under the Bilateral Credit Agreement were as follows:



(Millions of Dollars)	Limit		Amount Outstanding		Available
NSP-Minnesota	$	75	$	23	$	52

5. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues consists of the following:



	Three Months Ended June 30, 2019
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	288.1	$	40.9	$	7.1	$	336.1
Commercial and industrial	519.5		32.0		—		551.5
Other	7.6		—		1.3		8.9
Total retail	815.2		72.9		8.4		896.5
Wholesale	53.1		—		—		53.1
Transmission	55.3		—		—		55.3
Interchange	116.2		—		—		116.2
Other	3.9		1.8		—		5.7
Total revenue from contracts with customers	1,043.7		74.7		8.4		1,126.8
Alternative revenue and other	53.5		4.7		—		58.2
Total revenues	$	1,097.2	$	79.4	$	8.4	$	1,185.0



	Three Months Ended June 30, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	311.1	$	42.4	$	6.7	$	360.2
Commercial and industrial	514.7		33.4		—		548.1
Other	8.6		—		1.5		10.1
Total retail	834.4		75.8		8.2		918.4
Wholesale	42.0		—		—		42.0
Transmission	60.0		—		—		60.0
Interchange	117.4		—		—		117.4
Other	6.1		3.3		—		9.4
Total revenue from contracts with customers	1,059.9		79.1		8.2		1,147.2
Alternative revenue and other	36.5		4.0		—		40.5
Total revenues	$	1,096.4	$	83.1	$	8.2	$	1,187.7

~~Long-Term Borrowings~~



	Six Months Ended June 30, 2019
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	615.0	$	190.5	$	14.0	$	819.5
Commercial and industrial	987.0		140.8		—		1,127.8
Other	15.9		—		2.1		18.0
Total retail	1,617.9		331.3		16.1		1,965.3
Wholesale	100.0		—		—		100.0
Transmission	115.7		—		—		115.7
Interchange	236.3		—		—		236.3
Other	8.7		2.9		—		11.6
Total revenue from contracts with customers	2,078.6		334.2		16.1		2,428.9
Alternative revenue and other	97.3		9.3		—		106.6
Total revenues	$	2,175.9	$	343.5	$	16.1	$	2,535.5



	Six Months Ended June 30, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	622.2	$	174.1	$	13.0	$	809.3
Commercial and industrial	982.7		130.3		0.1		1,113.1
Other	18.4		—		2.2		20.6
Total retail	1,623.3		304.4		15.3		1,943.0
Wholesale	88.4		—		—		88.4
Transmission	114.7		—		—		114.7
Interchange	234.4		—		—		234.4
Other	17.6		5.5		—		23.1
Total revenue from contracts with customers	2,078.4		309.9		15.3		2,403.6
Alternative revenue and other	80.3		14.6		—		94.9
Total revenues	$	2,158.7	$	324.5	$	15.3	$	2,498.5

6. Income Taxes

Except to the extent noted below, Note 7 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2018 represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

The following table reconciles the difference between the statutory rate and the ETR:



	Six Months Ended June 30
	2019		2018
Federal statutory rate	21.0	%	21.0	%
State tax (net of federal tax effect)	7.1		7.1
Increases (decreases) in tax from:
Wind PTCs	(15.9	)	(17.1	)
Plant regulatory differences ^(a)	(8.0	)	(0.7	)
Other tax credits and allowances (net)	(1.2	)	(1.3	)
Other (net)	0.6		0.6
Effective income tax rate	3.6	%	9.6	%

^(a)

Regulatory differences for income tax primarily relate to the flow back of excess deferred taxes to customers through the average rate assumption method and the impact of allowance for funds used during construction - equity. Year-to-date variations primarily relates to the deferral of the flow back of excess deferred taxes in 2018, as a result of pending regulatory decisions. Treatment of most tax reform items was established prior to the first quarter of 2019, resulting in a reduction in deferred amounts. Income tax benefits associated with the flow back of excess deferred credits are offset by corresponding revenue reductions.

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



Tax Year(s)		Expiration
2009 - 2013		June 2020
2014 - 2016		September 2020
2017		September 2021

In 2015, the IRS commenced an examination of tax years 2012 and 2013. In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of June 30, 2019, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

In 2018, the IRS began an audit of tax years 2014 - 2016. As of June 30 2019 no adjustments have been proposed.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2019, 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 Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.

Unrecognized tax benefits - permanent vs temporary:



(Millions of Dollars)	June 30, 2019		Dec. 31, 2018
Unrecognized tax benefit — Permanent tax positions	$	12.8	$	11.6
Unrecognized tax benefit — Temporary tax positions	5.1		5.3
Total unrecognized tax benefit	$	17.9	$	16.9

~~In September 2017, NSP-Minnesota issued $600~~

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:



(Millions of Dollars)	June 30, 2019			Dec. 31, 2018
NOL and tax credit carryforwards	$	(14.6	)	$	(12.7	)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $9.3 million and $7.3 million at June 30, 2019 and Dec. 31, 2018, respectively.

As the IRS Appeals and federal audit progress, it is reasonably possible that the amount of ~~3.60 percent first mortgage bonds due Sept. 15, 2047.~~unrecognized tax benefit could decrease up to approximately $13.7 million in the next 12 months.

~~Debt Redemption~~

~~On Sept. 29, 2017, NSP-Minnesota reacquired $500 million~~Payables for interest related to unrecognized tax benefits were not material and no amounts were accrued for penalties related to unrecognized tax benefits as of ~~debt with a coupon rate of 5.25 percent and an original maturity date of March 1,~~June 30, 2019 or Dec. 31, 2018. ~~The redemption resulted in payment of an early redemption premium of $7.9 million which was deferred as a regulatory asset.~~


8.7.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosuresprovides a single definition of fair value, hierarchical framework for measuring assets and liabilities and requires ~~certain disclosures~~disclosure 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:~~include:

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

Investments in equity securities and other funds— Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using ~~NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value.~~NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. ~~Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice.~~ Private equity commingled fund 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 commingled funds investments may be redeemed with proper notice, ~~which is typically quarterly with 45-90 days notice;~~ however, withdrawals ~~from real estate investments~~ may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities— Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options generally utilize observable forward prices and volatilities, as well as observable pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification.

When contractual settlements relate to delivery locations for which pricing is relatively unobservable, or 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~~inputs on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as ~~financial transmission rights (FTRs), purchased from MISO.~~FTRs. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. ~~NSP-Minnesota’s valuation process for FTRs utilizes the cleared prices for each FTR for the most recent auction.~~

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited ~~transparency in~~observability of important inputs to the value of FTRs between auction ~~process,~~processes, 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 ~~limited transparency associated with~~numerous unobservable quantitative inputs pertinent to the ~~valuation~~value of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.

Non-Derivative ~~Instruments~~ Fair Value Measurements

~~Nuclear Decommissioning Fund~~

The Nuclear Regulatory Commission requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. ~~Together with all accumulated earnings or losses, the assets~~Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning ~~the Monticello and PI nuclear generating plants.~~these facilities. 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.~~investments. 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 nuclear plants, assuming rate recovery of all costs. ~~Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized~~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.~~

asset.

Unrealized gains for the nuclear decommissioning fund were ~~$511.7~~$606.3 million and ~~$378.6~~$450.1 million ~~at Sept.~~as of June 30, ~~2017~~2019 and Dec. 31, ~~2016,~~2018, respectively, and unrealized losses ~~and amounts recorded as other-than-temporary impairments~~ were ~~$10.3~~$15.0 million and ~~$46.9~~$44.8 million ~~at Sept.~~as of June 30, ~~2017~~2019 and Dec. 31, ~~2016,~~2018, respectively.

~~The following tables present the cost and fair value of NSP-Minnesota’s non-derivative~~

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning ~~fund at Sept. 30, 2017 and Dec. 31, 2016:~~fund:

Sept. 30, 2017
Fair Value
(Thousands of Dollars) Cost Level 1 Level 2 Level 3
Investments Measured at NAV ^(b)
Total
Nuclear decommissioning fund ^(a)

Cash equivalents $ 32,727
$ 32,727
$ —
$ —
$ —
$ 32,727
Commingled funds:
Non U.S. equities 257,487
204,502
—
—
86,654
291,156
Emerging market debt funds 97,285
—
—
—
106,842
106,842
Private equity investments 139,185
—
—
—
192,098
192,098
Real estate 129,219
—
—
—
195,506
195,506
Other commingled funds 146,179
14,964
—
—
145,313
160,277
Debt securities:
Government securities 45,310
—
44,944
—
—
44,944
U.S. corporate bonds 251,138
—
252,868
—
—
252,868
Non U.S. corporate bonds 46,245
—
46,611
—
—
46,611
Equity securities:
U.S. equities 258,075
509,564
—
—
—
509,564
Non U.S. equities 152,575
224,139
—
—
—
224,139
Total $ 1,555,425
$ 985,896
$ 344,423
$ —
$ 726,413
$ 2,056,732



	June 30, 2019
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	27.2	$	27.2	$	—	$	—	$	—	$	27.2
Commingled funds	801.7		—		—		—		987.7		987.7
Debt securities	484.7		—		473.0		14.4		—		487.4
Equity securities	396.3		797.8		1.1		—		—		798.9
Total	$	1,709.9	$	825.0	$	474.1	$	14.4	$	987.7	$	2,301.2


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$49.0~~$52.9 million of rabbi trust assets and miscellaneous investments.


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

Dec. 31, 2016
Fair Value
(Thousands of Dollars) Cost Level 1 Level 2 Level 3
Investments Measured at NAV ^(b)
Total
Nuclear decommissioning fund ^(a)

Cash equivalents $ 20,379
$ 20,379
$ —
$ —
$ —
$ 20,379
Commingled funds:
Non U.S. equities 260,877
133,126
—
—
112,233
245,359
Emerging market debt funds 93,597
—
—
—
97,543
97,543
Commodity funds 106,571
—
—
—
92,091
92,091
Private equity investments 132,190
—
—
—
190,462
190,462
Real estate 128,630
—
—
—
187,647
187,647
Other commingled funds 151,048
—
—
—
159,489
159,489
Debt securities:
Government securities 32,764
—
31,965
—
—
31,965
U.S. corporate bonds 104,913
—
105,772
—
—
105,772
Non U.S. corporate bonds 21,751
—
21,672
—
—
21,672
Municipal bonds 13,609
—
13,786
—
—
13,786
Mortgage-backed securities 2,785
—
2,816
—
—
2,816
Equity securities:
U.S. equities 270,779
473,400
—
—
—
473,400
Non U.S. equities 189,100
218,381
—
—
—
218,381
Total $ 1,528,993
$ 845,286
$ 176,011
$ —
$ 839,465
$ 1,860,762



	Dec 31, 2018
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	24.3	$	24.3	$	—	$	—	$	—	$	24.3
Commingled funds	758.1		79.2		—		—		819.1		898.3
Debt securities	465.6		—		435.6		—		—		435.6
Equity securities	401.4		696.5		—		—		—		696.5
Total	$	1,649.4	$	800.0	$	435.6	$	—	$	819.1	$	2,054.7


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$44.3~~$52.5 million of rabbi trust assets and miscellaneous investments.


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

For the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016~~2018 there ~~were~~was no ~~Level 3 nuclear decommissioning fund investments and no transfers~~transfer of amounts between levels.

~~The following table summarizes the final contractual~~Contractual maturity dates of ~~the~~ debt securities in the nuclear decommissioning fund ~~by asset class, at~~ ~~Sept.~~as of June 30, ~~2017~~:2019:



	Final Contractual Maturity
(Millions 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
Debt securities	$	1.4	$	121.6	$	224.9	$	139.5	$	487.4

Final Contractual Maturity
(Thousands of Dollars)
Due in 1 Year
or Less

Due in 1 to 5
Years

Due in 5 to 10
Years

Due after 10
Years
Total
Government securities $ —
$ 1,275
$ 2,303
$ 41,366
$ 44,944
U.S. corporate bonds 3,834
64,119
150,741
34,174
252,868
Non U.S. corporate bonds —
13,793
26,651
6,167
46,611
Debt securities $ 3,834
$ 79,187
$ 179,695
$ 81,707
$ 344,423

Rabbi Trusts

~~In June 2016,~~ NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions. ~~The following tables present the cost~~

Cost and fair value of ~~the~~ assets held in rabbi ~~trust at Sept. 30, 2017 and Dec. 31, 2016:~~trusts:



	June 30, 2019
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	0.4	$	0.4	$	—	$	—	$	0.4
Mutual funds	10.9		12.1		—		—		12.1
Total	$	11.3	$	12.5	$	—	$	—	$	12.5

Sept. 30, 2017
Fair Value
(Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trust ^(a)

Cash equivalents $ 391
$ 391
$ —
$ —
$ 391
Mutual funds 10,075
10,963
—
—
10,963
Total $ 10,466
$ 11,354
$ —
$ —
$ 11,354



	Dec. 31, 2018
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	0.4	$	0.4	$	—	$	—	$	0.4
Mutual funds	10.8		10.7		—		—		10.7
Total	$	11.2	$	11.1	$	—	$	—	$	11.1

Dec. 31, 2016
Fair Value
(Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts ^(a)

Cash equivalents $ 7,459
$ 7,459
$ —
$ —
$ 7,459
Mutual funds 1,663
1,901
—
—
1,901
Total $ 9,122
$ 9,360
$ —
$ —
$ 9,360


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

Derivative Instruments Fair Value Measurements

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

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

At ~~Sept.~~June 30, ~~2017,~~2019, accumulated other comprehensive ~~losses~~loss related to interest rate derivatives included ~~$0.6~~$0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact ~~earnings, including forecasted amounts for unsettled hedges, as applicable.~~earnings.

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

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

~~At Sept. 30, 2017,~~ NSP-Minnesota ~~had various vehicle fuel contracts designated as cash flow hedges extending through December 2018. NSP-Minnesota enters~~may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded inas 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.

At June 30, 2019, NSP-Minnesota ~~recorded immaterial amounts to income related to the ineffectiveness of~~had no commodity contracts designated as cash flow ~~hedges for the three and nine months ended Sept. 30, 2017 and 2016.~~hedges.no

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

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

~~The following table details the gross~~

Gross notional amounts of commodity forwards, options and ~~FTRs at Sept. 30, 2017 and Dec. 31, 2016:~~FTRs:

(Amounts in Thousands) ^(a)(b)
Sept. 30, 2017 Dec. 31, 2016
Megawatt hours of electricity 58,582
37,805
Million British thermal units of natural gas 47,329
79,520
Gallons of vehicle fuel 300
—


^(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.

Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of 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. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.

As of June 30, 2019, seven of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $43.9 million or 49% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Three of the 10 most significant counterparties, comprising $18.8 million or 21% of this credit exposure, were not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. Nine of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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



	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Three Months Ended June 30, 2019
Other derivative instruments
Electric commodity	$	—	$	15.6
Natural gas commodity	—		(0.2		)
Total	$	—	$	15.4

Six Months Ended June 30, 2019
Other derivative instruments
Electric commodity	$	—	$	(0.5	)
Natural gas commodity	—		(0.3		)
Total	$	—	$	(0.8	)

Three Months Ended June 30, 2018
Other derivative instruments
Electric commodity	$	—	$	24.3
Total	$	—	$	24.3

Six Months Ended June 30, 2018
Other derivative instruments
Electric commodity	$	—	$	(5.6	)
Natural gas commodity	—		0.8
Total	$	—	$	(4.8	)

Three Months Ended Sept. 30, 2017
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in: Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: Pre-Tax Gains Recognized
During the Period in Income
(Thousands of Dollars) Accumulated
Other
Comprehensive Loss Regulatory
(Assets) and Liabilities Accumulated
Other
Comprehensive Loss Regulatory
Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 612
^(a)
$ —
$ —

Vehicle fuel and other commodity 38
—
(11 )
^(b)
—
—

Total $ 38
$ —
$ 601
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 1,493
^(c)
Electric commodity —
20,216
—
(5,356 )
^(d)
—

Natural gas commodity —
(383 ) —
—

—

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



	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Three Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate	$	0.3	^(a)	$	—			$	—
Total	$	0.3		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	1.6		^(b)
Total	$	—		$	—			$	1.6

Six Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate	$	0.5	^(a)	$	—			$	—
Total	$	0.5		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	(1.2	)	^(b)
Electric commodity	—			0.8			^(c)	—
Natural gas commodity	—			0.2			^(d)	(1.3		)	^(d)
Total	$	—		$	1.0			$	(2.5	)
Three Months Ended June 30, 2018
Derivatives designated as cash flow hedges
Interest rate	$	0.3	^(a)	$	—			$	—
Total	$	0.3		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	2.3		^(b)
Electric commodity	—			1.1			^(c)	—
Total	$	—		$	1.1			$	2.3

Six Months Ended June 30, 2018
Derivatives designated as cash flow hedges
Interest rate	$	0.5	^(a)	$	—			$	—
Total	$	0.5		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	9.0		^(b)
Electric commodity	—			3.3			^(c)	—
Natural gas commodity	—			(0.5		)	^(d)	(0.4		)	^(d)
Total	$	—		$	2.8			$	8.6

Nine Months Ended Sept. 30, 2017
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in: Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: Pre-Tax Gains (Losses)
Recognized
During the Period in Income
(Thousands of Dollars) Accumulated
Other
Comprehensive Loss Regulatory
(Assets) and Liabilities Accumulated
Other
Comprehensive Loss Regulatory
Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 1,304
^(a)
$ —
$ —

Vehicle fuel and other commodity 81
—
(16 )
^(b)
—
—

Total $ 81
$ —
$ 1,288
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 8,092
^(c)
Electric commodity —
17,444
—
(9,293 )
^(d)
—

Natural gas commodity —
(1,010 ) —
698
^(e)
(945 )
^(e)
Total $ —
$ 16,434
$ —
$ (8,595 ) $ 7,147

Three Months Ended Sept. 30, 2016
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in: Pre-Tax Losses
Reclassified into Income
During the Period from: Pre-Tax Gains
Recognized
During the Period in Income
(Thousands of Dollars) Accumulated
Other
Comprehensive Loss Regulatory
(Assets) and Liabilities Accumulated
Other
Comprehensive Loss Regulatory
Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 350
^(a)
$ —
$ —

Vehicle fuel and other commodity (2 ) —
25
^(b)
—
—

Total $ (2 ) $ —
$ 375
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 1,808
^(c)
Electric commodity —
15,301
—
2,044
^(d)
—

Natural gas commodity —
(792 ) —
—
—

Total $ —
$ 14,509
$ —
$ 2,044
$ 1,808

Nine Months Ended Sept. 30, 2016
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in: Pre-Tax Losses
Reclassified into Income
During the Period from: Pre-Tax Gains (Losses)
Recognized
During the Period in Income
(Thousands of Dollars) Accumulated
Other
Comprehensive Loss Regulatory
(Assets) and Liabilities Accumulated
Other
Comprehensive Loss Regulatory
Assets and(Liabilities)
Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 1,042
^(a)
$ —
$ —

Vehicle fuel and other commodity 8
—
82
^(b)
—
—

Total $ 8
$ —
$ 1,124
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 3,069
^(c)
Electric commodity —
12,550
—
26,328
^(d)
—

Natural gas commodity —
(1,045 ) —
3,460
^(e)
(1,595 )
^(e)
Total $ —
$ 11,505
$ —
$ 29,788
$ 1,474


^(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)(c)	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) (d)	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~~six months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.~~2018.

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

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

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance ~~sheet,~~sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross-default contractual provisions ~~that could result in the settlement of such contracts~~ if there was a failure under other financing arrangements related to payment terms or other covenants. At ~~Sept.~~June 30, ~~2017~~2019 and Dec. 31, ~~2016, there were no~~2018, $5.8 million and less than $1.0 million of derivative instruments were in a ~~material~~ liability position with such underlying contract ~~provisions.~~

provisions, respectively, with no offsetting positions or posted collateral.

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.~~June 30, ~~2017~~2019 and Dec. 31, ~~2016.~~2018.

Recurring Fair Value Measurements — ~~The following table presents for each of the fair value hierarchy levels,~~ NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring ~~basis at Sept. 30, 2017:~~basis:

Counterparty Netting ^(b)

Dec. 31, 2016
Fair Value Fair Value Total
Counterparty Netting ^(b)

(Thousands of Dollars) Level 1 Level 2 Level 3 Total
Current derivative liabilities
Other derivative instruments:
Commodity trading $ 12,397
$ 5,964
$ —
$ 18,361
$ (15,837 ) $ 2,524
Electric commodity —
—
677
677
(677 ) —
Total current derivative liabilities $ 12,397
$ 5,964
$ 677
$ 19,038
$ (16,514 ) 2,524
PPAs ^(a)
14,082
Current derivative instruments $ 16,606
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading $ 89
$ 23,424
$ —
$ 23,513
$ (10,727 ) $ 12,786
Total noncurrent derivative liabilities $ 89
$ 23,424
$ —
$ 23,513
$ (10,727 ) 12,786
PPAs ^(a)
104,018
Noncurrent derivative instruments $ 116,804

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

Nine Months Ended Sept. 30
(Thousands of Dollars) 2017 2016
Balance at Jan. 1 $ 15,320
$ 12,969
Purchases 40,740
27,870
Settlements (34,681 ) (38,300 )
Net transactions recorded during the period:
Gains (losses) recognized in earnings ^(a)
5,742
(2 )
Net gains recognized as regulatory assets and liabilities 18,292
21,922
Balance at Sept. 30 $ 45,413
$ 24,459



	Three Months Ended June 30
(Millions of Dollars)	2019			2018
Balance at April 1	$	(10.0	)	$	13.5
Purchases	16.7			26.4
Settlements	(3.1		)	(5.2		)
Net transactions recorded during the period:
Gains (losses) gains recognized in earnings ^(a)	7.0			(2.6		)
Net losses recognized as regulatory assets and liabilities	(4.6		)	(4.1		)
Balance at June 30	$	6.0		$	28.0
	Six Months Ended June 30
	2019			2018
Balance at Jan. 1	$	14.3		$	22.7
Purchases	16.7			26.4
Settlements	(6.4		)	(7.1		)
Net transactions recorded during the period:
Losses recognized in earnings ^(a)	(11.6		)	(0.4		)
Net losses recognized as regulatory assets and liabilities	(7.0		)	(13.6		)
Balance at June 30	$	6.0		$	28.0

NSP-Minnesota recognizes transfers between fair value hierarchy levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016.~~2018.

Fair Value of Long-Term Debt

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



	June 30, 2019				Dec. 31, 2018
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,939.3	$	5,598.1	$	4,937.2	$	5,230.9

Sept. 30, 2017 Dec. 31, 2016
(Thousands of Dollars)
Carrying
Amount
Fair Value Carrying
Amount Fair Value
Long-term debt, including current portion $ 4,932,977
$ 5,501,602
$ 4,843,165
$ 5,310,925

8. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost



	Three Months Ended June 30
	2019			2018			2019			2018
(Millions of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6.3		$	6.9		$	—		$	0.1
Interest cost ^(a)	9.3			8.8			0.8			0.8
Expected return on plan assets ^(a)	(13.6		)	(14.5		)	—			(0.1		)
Amortization of prior service cost (credit) ^(a)	—			—			(0.8		)	(0.8		)
Amortization of net loss ^(a)	7.6			9.6			0.4			0.6
Net periodic benefit cost	9.6			10.8			0.4			0.6
Costs not recognized due to the effects of regulation	(1.5		)	(3.0		)	—			—
Net benefit cost recognized for financial reporting	$	8.1		$	7.8		$	0.4		$	0.6



	Six Months Ended June 30
	2019			2018			2019			2018
(Millions of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	12.7		$	14.0		$	0.1		$	0.1
Interest cost ^(a)	18.5			17.6			1.6			1.5
Expected return on plan assets ^(a)	(27.1		)	(29.1		)	(0.1		)	(0.2		)
Amortization of prior service (credit) cost ^(a)	(0.1		)	—			(1.5		)	(1.5		)
Amortization of net loss ^(a)	15.1			19.2			0.7			1.2
Net periodic benefit cost	19.1			21.7			0.8			1.1
Costs not recognized due to the effects of regulation	(2.7		)	(5.9		)	—			—
Net benefit cost recognized for financial reporting	$	16.4		$	15.8		$	0.8		$	1.1


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

In January 2019, contributions of $150 million were made across four of Xcel Energy’s pension plans, of which $47 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2019.

~~Other income (expense), net consisted~~

9. Commitments and Contingencies

Legal

NSP-Minnesota is involved in various litigation matters 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 losses 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, would have a material effect on NSP-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Rate Matters

Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional and subject to further review following conclusion of litigation commenced by NSP-Minnesota, SMMPA (Co-owner of Sherco Unit 3) and insurance companies against GE.

In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP‑Minnesota has notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA. The insurance providers continued their litigation against GE and the case went to trial. In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP‑Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the ~~following:~~trial.

In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently agreed with the OAG’s recommendation to withhold a decision pending the outcome of any appeals. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable.

In March 2019, MPUC approved NSP-Minnesota’s proposal to refund the GE settlement proceeds back to customers through the FCA. It also decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of the pending litigation between GE and NSP-Minnesota’s insurers.

MISO ROE Complaints — In November 2013 and February 2015, customers filed complaints against MISO TOs including NSP-Minnesota and NSP-Wisconsin. The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15%, and removal of ROE adders (including those for RTO membership).The second complaint sought to reduce base ROE from 12.38% to 8.67%. In September 2016, the FERC issued an order granting a 10.32% base ROE (10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based.

In October 2018, the FERC issued an ROE order that addressed the D.C. Circuit’s actions. Under a new proposed two step ROE approach, the FERC indicated an intention to dismiss an ROE complaint if the existing ROE falls within the range of just and reasonable ROEs based on equal weighting of the DCF, APM, and Expected Earnings models. The FERC proposed that if necessary, it would then set a new ROE by averaging the results of these models plus a Risk Premium model.

The FERC subsequently made preliminary determinations in a November 2018 order that the MISO TO’s base ROE in effect for the first complaint period (12.38%) was outside the range of reasonableness, and should be reduced. The FERC indicated its preliminary analysis using the new ROE approach resulted in a base ROE of 10.28% for the first complaint period, compared to the previously ordered base ROE of 10.32%. NSP-Minnesota has recognized a current refund liability consistent with its best estimate of the final ROE, pending further FERC action as early as the second half of 2019.

On March 21, 2019, FERC announced a NOI seeking public comments on whether, and if so how, to revise ROE policies in light of the D.C. Circuit Court decision. FERC also initiated a NOI on whether to revise its policies on incentives for electric transmission investments, including the RTO membership incentive. Initial comments on both NOIs are due in June 2019, with reply comments due in the third quarter of 2019. No final FERC action is expected before the second half of 2019.

Environmental

MGP, Landfill or Disposal Sites — NSP-Minnesota is currently investigating or remediating six MGP, landfill or other disposal sites across its service territories.

NSP-Minnesota has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of the costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation —NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste.

Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. By the end of 2019, only three of NSP-Minnesota’s regulated ash units are expected to be in operation. NSP-Minnesota is conducting groundwater sampling, and where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments.

Until NSP-Minnesota completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.

Leases

NSP-Minnesota evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by NSP-Minnesota on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

ROU assets represent NSP-Minnesota's rights to use leased assets. Starting in 2019, the present value of future operating lease payments are recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of NSP-Minnesota’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is calculated using the estimated incremental borrowing rate (weighted-average of 3.8%). NSP-Minnesota has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.

Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.

Operating lease ROU assets:



(Millions of Dollars)	June 30, 2019
PPAs	$	556.3
Other	72.2
Gross operating lease ROU assets	628.5
Accumulated amortization	(27.0		)
Net operating lease ROU assets	$	601.5

Components of lease expense:

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Thousands of Dollars) 2017 2016 2017 2016
Interest income $ 2,936
$ 510
$ 6,250
$ 3,975
Other nonoperating income —
—
—
248
Insurance policy expense (387 ) (926 ) (2,098 ) (2,389 )
Other nonoperating expense (429 ) (23 ) (402 ) —
Other income (expense), net $ 2,120
$ (439 ) $ 3,750
$ 1,834



(Millions of Dollars)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating leases
PPA capacity payments	$	15.9	$	31.2
Other operating leases ^(a)	2.3		4.6
Total operating lease expense ^(b)	$	18.2	$	35.8


~~10.~~ ^(a)	~~Segment Information~~Includes short-term lease expense of $0.4 million for three months ended June 30, 2019 and $0.8 million for six months ended June 30, 2019.


^(b)	PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

NSP-Minnesota has requested regulatory approval to purchase the MEC in the third quarter of 2019. NSP-Minnesota currently receives energy and capacity from MEC under PPAs expiring in 2026 and 2039. Pending its expected purchase by NSP-Minnesota, operating lease liabilities at June 30, 2019 currently include a present value of $428 million for PPA capacity payments.

Future commitments under operating leases as of June 30, 2019:



(Millions of Dollars)	PPA ^{(a) (b)} Operating Leases			Other Operating Leases			Total Operating Leases
2019	$	46.3		$	3.9		$	50.2
2020	93.5			7.9			101.4
2021	94.9			8.0			102.9
2022	96.4			11.9			108.3
2023	97.9			7.0			104.9
Thereafter	219.3			51.8			271.1
Total minimum obligation	648.3			90.5			738.8
Interest component of obligation	(76.6		)	(18.1		)	(94.7		)
Present value of minimum obligation	$	571.7		$	72.4		644.1
Less current portion							(77.8		)
Noncurrent operating lease liabilities							$	566.3

Weighted-average remaining lease term in years							7.2


^(a)	Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.


^(b)	PPA operating leases contractually expire at various dates through 2026.

Future commitments under operating leases as of Dec. 31, 2018:



(Millions of Dollars)	PPA ^{(a) (b)} Operating Leases		Other Operating Leases		Total Operating Leases
2019	$	65.0	$	13.5	$	78.5
2020	66.1		8.4		74.5
2021	67.1		8.4		75.5
2022	68.2		8.1		76.3
2023	69.3		7.3		76.6
Thereafter	143.5		36.0		179.5


^(a)	Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.


^(b)	PPA operating leases contractually expire at various dates through 2026.

Variable Interest Entities

Under certain PPAs, NSP-Minnesota purchases power from IPPs and is required to reimburse the IPPs for 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 IPP.

NSP-Minnesota had approximately 1,347 MW and 1,002 MW of capacity under long-term PPAs at June 30, 2019 and Dec. 31, 2018, respectively, with entities that have been determined to be VIEs. NSP-Minnesota concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that significantly impact the entities’ economic performance. These agreements have various expiration dates through 2027.

10. Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss), net of tax, for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30, 2019											Three Months Ended June 30, 2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at April 1	$	(20.0	)	$	—	$	(2.9	)	$	(22.9	)	$	(20.7	)	$	—	$	(3.7	)	$	(24.4	)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.1, $0, $0, $0.1, $0 and $0, respectively) ^(a)	0.2			—		—			0.2			0.2			—		—			0.2
Net current period other comprehensive income	0.2			—		—			0.2			0.2			—		—			0.2
Accumulated other comprehensive loss at June 30	$	(19.8	)	$	—	$	(2.9	)	$	(22.7	)	$	(20.5	)	$	—	$	(3.7	)	$	(24.2	)



	Six Months Ended June 30, 2019											Six Months Ended June 30, 2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive income (loss) at Jan. 1	$	(20.2	)	$	—	$	(2.9	)	$	(23.1	)	$	(20.9	)	$	0.1		$	(3.8	)	$	(24.6	)
Losses (gains) reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.1, $0, $0, $0.1, $(0.1) and $0, respectively) ^(a)	0.4			—		—			0.4			0.4			(0.1		)	—			0.3
Amortization of net actuarial loss (net of taxes of $0) ^(b)	—			—		—			—			—			—			0.1			0.1
Net current period other comprehensive income	0.4			—		—			0.4			0.4			(0.1		)	0.1			0.4
Accumulated other comprehensive loss at June 30	$	(19.8	)	$	—	$	(2.9	)	$	(22.7	)	$	(20.5	)	$	—		$	(3.7	)	$	(24.2	)

11. 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.

•

Regulated Electric — The regulated electric utility segment generates electricity which is transmitted and distributed in 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. The regulated electric utility segment also includes NSP-Minnesota’s wholesale commodity and trading operations.


•	Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota.


•	All Other — Operating segments with revenues below the necessary quantitative thresholds are included in this category. Those primarily include appliance repair services, non-utility 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~~basis.Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation ~~allocators. A~~allocators across each segment.

In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. NSP-Minnesota’s segment information for the three and six months ended June 30:

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


(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2016
													Three Months Ended June 30
(Millions of Dollars)													2019			2018
Regulated Electric
Operating revenues^(a)													$	1,097.2		$	1,096.4
Intersegment revenues													0.2			0.1
Total revenue													1,097.4			1,096.5
Net income													93.9			88.9
Regulated Natural Gas
Operating revenues^(b)													$	79.4		$	83.1
Intersegment revenues													0.2			0.1
Total revenue													79.6			83.2
Net income													0.3			0.4
All Other
Operating revenues													$	8.4		$	8.2
Net gain													1.7			3.1
Consolidated Total
Operating revenues ^(a)(b)	$	1,282,574	$	55,519		$	7,286	$	—		$	1,345,379	$	1,185.4		$	1,187.9
Intersegment revenues	118		189			—		(307		)	—
Reconciling eliminations													(0.4		)	(0.2		)
Total revenues	$	1,282,692	$	55,708		$	7,286	$	(307	)	$	1,345,379	$	1,185.0		$	1,187.7
Net income (loss)	$	217,674	$	(14,900	)	$	3,778	$	—		$	206,552
Net income													95.9			92.4


^(a)	Operating revenues include ~~$124~~$116.2 million and ~~$121~~$117.4 million of affiliate electric revenue for the three months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016.~~2018.


^(b)	Operating revenues ~~include~~includes an immaterial amount of affiliate gas revenue for the three months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016.~~2018.

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



	Six Months Ended June 30
(Millions of Dollars)	2019			2018
Regulated Electric
Operating revenues^(a)	$	2,175.9		$	2,158.7
Intersegment revenues	0.3			0.3
Total revenue	2,176.2			2,159.0
Net income	176.8			174.6
Regulated Natural Gas
Operating revenues^(b)	$	343.5		$	324.5
Intersegment revenues	0.5			0.3
Total revenue	344.0			324.8
Net income	29.0			25.8
All Other
Operating revenues	$	16.1		$	15.3
Net gain	3.3			3.7
Consolidated Total
Operating revenues^(a)(b)	$	2,536.3		$	2,499.1
Reconciling eliminations	(0.8		)	(0.6		)
Total revenues	$	2,535.5		$	2,498.5
Net income	209.1			204.1

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


^(a)	Operating revenues include ~~$367~~$236.3 million and ~~$359~~$234.4 million of affiliate electric revenue for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016.~~2018.


^(b)	Operating revenues ~~include~~includes an immaterial amount of affiliate gas revenue for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2019 and ~~2016.~~2018.


~~11.~~	~~Benefit Plans and Other Postretirement Benefits~~

~~Components of Net Periodic Benefit Cost~~

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

Nine Months Ended Sept. 30
2017 2016 2017 2016
(Thousands of Dollars) Pension Benefits
Postretirement Health
Care Benefits
Service cost $ 20,874
$ 21,231
$ 108
$ 93
Interest cost 30,531
34,074
2,562
2,943
Expected return on plan assets (45,050 ) (45,708 ) (161 ) (129 )
Amortization of prior service cost (credit) 795
702
(2,277 ) (2,277 )
Amortization of net loss 29,706
27,582
1,520
1,203
Net periodic benefit cost 36,856
37,881
1,752
1,833
Costs not recognized due to the effects of regulation (14,696 ) (15,887 ) —
—
Net benefit cost recognized for financial reporting $ 22,160
$ 21,994
$ 1,752
$ 1,833

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


~~12.~~	~~Other Comprehensive Income (Loss)~~

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

Three Months Ended Sept. 30, 2017
(Thousands of Dollars)
Gains and
Losses on Cash Flow
Hedges

Unrealized
Gains on Marketable
Securities

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

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

Nine Months Ended Sept. 30, 2017
(Thousands of Dollars) Gains and
Losses on Cash Flow Hedges Unrealized
Gains on Marketable
Securities Defined Benefit
Pension and
Postretirement Items Total
Accumulated other comprehensive (loss) income at Jan. 1 $ (18,208 ) $ 105
$ (2,680 ) $ (20,783 )
Other comprehensive income before reclassifications 48
—
—
48
Losses reclassified from net accumulated other comprehensive loss 786
—
110
896
Net current period other comprehensive income 834
—
110
944
Accumulated other comprehensive (loss) income at Sept. 30 $ (17,374 ) $ 105
$ (2,570 ) $ (19,839 )

Nine Months Ended Sept. 30, 2016
(Thousands of Dollars) Gains and
Losses on Cash Flow Hedges Unrealized
Gains on Marketable
Securities Defined Benefit
Pension and
Postretirement Items Total
Accumulated other comprehensive (loss) income at Jan. 1 $ (19,090 ) $ 105
$ (2,096 ) $ (21,081 )
Other comprehensive income before reclassifications 5
—
—
5
Losses reclassified from net accumulated other comprehensive loss 657
—
57
714
Net current period other comprehensive income 662
—
57
719
Accumulated other comprehensive (loss) income at Sept. 30 $ (18,428 ) $ 105
$ (2,039 ) $ (20,362 )

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

Amounts Reclassified from
Accumulated Other
Comprehensive Loss
(Thousands of Dollars) Three Months Ended Sept. 30, 2017 Three Months Ended Sept. 30, 2016
Losses (gains) on cash flow hedges:
Interest rate derivatives $ 612
^(a)
$ 350
^(a)
Vehicle fuel derivatives (11 )
^(b)
25
^(b)
Total, pre-tax 601
375

Tax benefit (222 ) (162 )
Total, net of tax 379
213

Defined benefit pension and postretirement losses:
Amortization of net loss 109
^(c)
83
^(c)
Prior service credit (49 )
^(c)
(49 )
^(c)
Total, pre-tax 60
34

Tax benefit (21 ) (15 )
Total, net of tax 39
19

Total amounts reclassified, net of tax $ 418
$ 232

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

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

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

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

Total amounts reclassified, net of tax $ 896
$ 714


^(a)	~~Included in interest charges.~~


^(b)	~~Included in O&M expenses.~~


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

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)~~ 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)~~ H(2)(a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Non-GAAP Financial ~~Review~~

Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. NSP-Minnesota’s management uses non-GAAP measures for financial planning and analysis, ~~by management focuses on those factors that had a material effect on NSP-Minnesota’s~~for reporting of results, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors.

Non-GAAP 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 statementsmeasures are intended to supplement investors’ understanding of our performance and should not be ~~identified~~considered alternatives for financial measures presented in ~~this document by~~accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the ~~words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should”~~cost of natural gas sold and ~~similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made,~~transported. Expenses incurred for electric fuel and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including NSP-Minnesota’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2016 and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditurespurchased power and the ~~ability~~cost of ~~NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions~~natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in ~~the energy industry; including the risk of a slow down~~these expenses are generally offset 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 theoperating revenues.

Management believes electric and natural gas ~~markets; costs and~~margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability oroperating revenues, cost of ~~capital;~~sales-other, O&M expenses, conservation and ~~employee work force factors.~~

state implementation plan expenses, depreciation and amortization and taxes (other than income taxes).

Results of Operations

NSP-Minnesota’s net income was approximately ~~$410.8~~$209.1 million for ~~2017~~2019 year-to-date, compared with approximately ~~$379.4~~$204.1 million for the same period of ~~2016.~~2018. The ~~year-to-date~~ increase in year-to-date earnings primarily reflects higher electric margins driven by rate ~~increases, lower ETR and reduced O&M expenses. These positive factors were~~case outcomes, partially offset by increased depreciation ~~expense~~ and ~~higher property taxes.~~

O&M expenses.

Electric ~~Revenues and~~ Margin

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. ~~The following table details the~~In addition, electric customers receive a credit for PTCs that are generated in a particular period.

Electric revenues and margin:


	Nine Months Ended Sept. 30						Six Months Ended June 30
(Millions of Dollars)	2017			2016			2019			2018
Electric revenues	$	3,450		$	3,333		$	2,175.9		$	2,158.7
Electric fuel and purchased power	(1,215		)	(1,149		)	(796.3		)	(824.3		)
Electric margin	$	2,235		$	2,184		$	1,379.6		$	1,334.4

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

~~Electric Revenues~~margin:

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

~~Electric Margin~~

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



(Millions of Dollars)	2019 vs. 2018
Regulatory rate outcomes (Minnesota, North and South Dakota)	$	35.6
Non-fuel riders	17.0
Interchange agreement billings with NSP-Wisconsin	7.0
Wholesale transmission margin	6.3
Conservation program revenue (offset by expenses)	5.1
Timing of TCJA regulatory decisions (offset in income tax)	(24.7		)
Estimated impact of weather, net of Minnesota decoupling	(3.2		)
Other (net)	2.1
Total increase in electric margin	$	45.2

Natural Gas ~~Revenues and~~ Margin

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

Natural gas revenues and margin:



	Six Months Ended June 30
(Millions of Dollars)	2019			2018
Natural gas revenues	$	343.5		$	324.5
Cost of natural gas sold and transported	(208.3		)	(192.1		)
Natural gas margin	$	135.2		$	132.4

Nine Months Ended Sept. 30
(Millions of Dollars) 2017 2016
Natural gas revenues $ 357
$ 314
Cost of natural gas sold and transported (199 ) (164 )
Natural gas margin $ 158
$ 150

~~The following tables summarize the components of the changes~~

Changes in natural gas ~~revenues and natural gas margin for the nine months ended Sept. 30:~~

~~Natural Gas Revenues~~margin:

(Millions of Dollars) 2017 vs. 2016
Purchased natural gas adjustment clause recovery $ 34
Conservation program revenue, offset by expenses 4
Retail sales growth, excluding weather impact 3
Infrastructure and integrity riders 3
Other, net (1 )
Total increase in natural gas revenues $ 43

~~Natural Gas Margin~~

(Millions of Dollars) 2017 vs. 2016
Conservation program revenue, offset by expenses $ 4
Retail sales growth, excluding weather impact 3
Infrastructure and integrity riders 3
Other, net (2 )
Total increase in natural gas margin $ 8



(Millions of Dollars)	2019 vs. 2018
Estimated impact of weather	$	3.0
Infrastructure rider	1.5
Conservation program revenue (offset by expenses)	(2.8		)
Other (net)	1.1
Total increase in natural gas margin	$	2.8

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses ~~decreased $45.0~~increased $15.9 million, or ~~4.7 percent,~~2.6%, for ~~2017~~2019 year-to-date. ~~The decrease primarily relates to the timing of maintenance activities~~Increase was driven by increased consulting costs, higher insurance premiums, higher employee benefit expenses, and ~~the overhauls at various generation facilities and reduced expense for nuclear refueling outages, as summarized in the table below:~~

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

~~Conservation Program Expenses~~ ~~— Conservation program expenses increased $24.8 million, for 2017 year-to-date. The increase was~~flooding costs due to higher recovery rates and additional customer participation in electric conservation programs. Conservation expenses are generally recovered in major jurisdictions concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred.storms.

Depreciation and Amortization— Depreciation and amortization expense increased ~~$79.4~~$35.0 million, or ~~17.9 percent,~~9.7%, for ~~2017~~2019 year-to-date. ~~The increase~~Increase was primarily due to increased capital investments ~~including~~with the ~~Courtenay Wind Farm~~largest projects being Monticello's dry fuel storage, Prairie Island’s generator replacements and ~~prior year amortization of the excess depreciation reserve.~~various software solutions. There was also an increase in non-fuel rider amortization.

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

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

Income Taxes — Income tax expense decreased ~~$35.3~~$13.9 million for the first ~~nine~~six months of ~~2017. The decrease~~2019 compared to the same period in 2018. Decrease was primarily ~~due to net tax benefits related to~~driven by an increase in plant-related regulatory differences and lower pretax income. This was partially offset by a decrease in wind ~~production tax credits (PTCs)~~PTCs. Wind PTCs flow back to customers (recorded as a reduction to revenue) and ~~the resolution of IRS appeals/audits.~~do not have a material impact on net income. The ETR was ~~25.5 percent~~3.6% for ~~2017 year-to-date,~~the first six months of 2019 compared with ~~31.7 percent~~9.6% for the same period in ~~2016.~~2018. The lower ETR in ~~2017 was~~2019 is primarily due to the ~~adjustments~~items referenced above. See Note 6 to the consolidated financial statements for further information.

Regulation

FERC and State Regulation — 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.

Xcel Energy, which includes NSP-Minnesota, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations. Decisions by these regulators can significantly impact NSP-Minnesota’s results of operations.

Other Pending and Recently Concluded Regulatory Proceedings



Mechanism	Utility Service	Amount Requested (in millions)	Filing Date	Approval	Additional Information
NSP-Minnesota (MPUC)
TCR	Electric	$98	November 2017	Pending	In May 2019, the MPUC issued a verbal order setting an ROE of 9.06% and recovery of 2017-2018 expenses related to advanced grid investments. A final order is expected in the third quarter of 2019.
2018 GUIC	Natural Gas	$23	November 2017	Pending	In May 2019, the MPUC issued a verbal order setting an ROE of 9.04%. A final order is expected in the third quarter of 2019.
2019 GUIC	Natural Gas	$29	November 2018	Pending	Proposed ROE of 10.25%. Timing of the MPUC decision is uncertain.
RES	Electric	$23	November 2017	Pending	In May 2019, the MPUC issued a verbal order setting an ROE of 9.06%. A final order is expected in the third quarter of 2019.

See Rate Matters within Note 9 to the consolidated financial statements for further information.

MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company to purchase the 760 MW natural gas CC facility for approximately $650 million. NSP-Minnesota currently purchases the energy and capacity of this facility through PPAs. The acquisition is projected to provide net customer savings of approximately $50 million to $150 million over the life of the plant.

In May 2019, NSP-Minnesota entered into a partial settlement agreement with several environmental organizations and the LIUNA. Under the terms of the agreement, the settling parties supported the MEC acquisition and NSP-Minnesota agreed to include (in its preferred plan in the Minnesota resource plan filing) early retirement of the Sherco 3 and King coal plants, as well as 3,000 MW of solar additions before 2030.

In May 2019, the FERC approved the purchase. In July 2019, the DOC and OAG recommended the MPUC deny approval of the Mankato acquisition. The DOC and OAG also recommended that if the MPUC were to approve the transaction, that the Commission disallow all or a portion of the acquisitions adjustment as well as require certain other customer protections. The MPUC is expected to hold hearings and make a decision in the third quarter.

Minnesota Resource Plan —In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The preferred plan would result in an 80% carbon reduction by 2030 and puts NSP on a path to achieving its vision of being 100% carbon-free by 2050. The preferred plan includes the following:

Extends the life of the Monticello nuclear plant from 2030 to 2040;

Continues to run the Prairie Island nuclear plant through current end of life (2033 and 2034);

Includes the MEC acquisition and construction of the Sherco CC natural gas plant;

Includes the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;

Adds approximately 1,700 MW of firm peaking (CT, pumped hydro, battery storage, DR, etc.);

Adds approximately 1,200 MW of wind replacement; and

Adds approximately 4,000 MW of solar.

Intervening parties will provide recommendations and comments on the resource plan. The MPUC is anticipated to make a final decision on the resource plan in late 2020 or the first half of 2021.

Jeffers Wind and CommunityWind North Repowering Acquisition— In December 2018, NSP-Minnesota filed a request with the MPUC seeking approval to acquire the Jeffers and Community Wind North wind facilities in western Minnesota from Longroad Energy. The wind ~~PTCs largely flow back~~farms, currently contracted under PPAs with NSP-Minnesota, will have approximately 70 MW of capacity after being repowered. The repowering and acquisition are expected to ~~customers through electric margin.~~be complete by December 2020 and qualify for the 100% PTC benefit. The $135 million asset acquisition is projected to provide customer savings of approximately $7 million over the life of the facilities, compared to the amended PPAs. The FERC approved the acquisition in July 2019.

The DOC filed initial comments in support of NSP-Minnesota continuing to contract for the assets under the amended PPAs, but not the acquisition, pending additional information, including a purchase and sales agreement. NSP-Minnesota subsequently filed additional information, including an executed purchase and sale agreement, to address DOC concerns. Reply comments are due in August, with an MPUC decision expected in the second half of 2019.

Public Utility Regulation

Except to the extent noted below and in Regulation above, the circumstances set forth in Public Utility Regulation included in Item 1 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2016~~2018 and ~~Public Utility Regulation included~~ in Item 2 of ~~NSP-Minnesota’s~~NSP-Minnesota's Quarterly Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2017 and June 30, 2017,~~2019, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated ~~herein~~ by reference.

~~Wind Development~~ South Dakota Proxy Pricing — In ~~July 2017,~~January 2018, NSP-Minnesota requested approval of a proxy price proposal (i.e., pricing broadly representing the ~~MPUC approved NSP-Minnesota’s proposal~~overall market) to ~~add 1,550 MW~~address treatment of ~~new~~certain purchase power costs for wind, ~~generation, including ownership of 1,150 MW of~~solar and biomass being recovered through the South Dakota fuel clause rider. SDPUC Staff submitted a counter-proposal, which would set certain solar and wind ~~generation by NSP-Minnesota.~~contracts at a price lower than current fuel clause rates. Discussions with SDPUC Staff are ongoing and a final decision is expected later in 2019.

Minnesota State ROFR Statute Complaint — In September 2017, ~~NSP-Minnesota~~LSP Transmission filed ~~with the MPUC seeking approval to build and own the Dakota Range project,~~ a 300 MW wind project in South Dakota. The project is projected to be placed into service by the end of 2021 to qualify for 80 percent of the PTC. NSP-Minnesota has requested that the MPUC approve the proposed wind project by March 2018.

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

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

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

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

Total Wind Capacity 1,850

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

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

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

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

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

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

~~CapX2020~~ — The estimated cost of the five major CapX2020 transmission projects listed below was approximately $2 billion. NSP-Minnesota and NSP-Wisconsin were responsible for approximately $1.04 billion of the total investment and the majority of this investment has occurred. The projects are as follows:

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

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

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

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

~~Big Stone South to Brookings County, S.D.~~new 345 KV transmission line ~~— The project was placed in service in September 2017.~~

~~Minnesota FCA~~ ~~— In October 2017, the MPUC voted to change the process in which utilities seek fuel cost recovery under the FCA in Minnesota. Each month, utilities collect amounts equal to the baseline~~(estimated cost of ~~energy set at~~$108 million), consistent with a Minnesota state ROFR statute. The complaint challenged the ~~start~~constitutionality of the ~~plan year, as well as issue refunds or billings for~~state ROFR statute and is seeking declaratory judgment that the ~~difference relative~~statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. In June 2018, the ~~baseline costs. Under~~Minnesota District Court granted the ~~new process, monthly variations~~defendants’ motions to ~~the baseline costs~~dismiss with prejudice. LSP Transmission filed an appeal in July 2018. It is uncertain when a decision will be ~~tracked~~rendered.

MISO Generator Replacement Tariff Change - In February 2019, MISO filed to modify the generator interconnection provisions of its tariff to allow generator replacements at existing generation sites. The tariff changes would facilitate the proposed Sherco 1 and ~~netted over a 12-month period. Subsequently, utilities can seek recovery of any overage. The MPUC has requested additional compliance filings from all utilities outlining the details~~2 coal to natural gas conversion project. Xcel Energy and ~~timing~~other parties filed comments in support of the ~~proposed process.~~ tariff changes. NextEra Energy and the Sierra Club, among others, protested the proposal. In May 2019, FERC issued an order approving the tariff revisions.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PIPrairie Island plant. ~~NSP-Minnesota’s next triennial nuclear decommissioning filing is expected to be submitted in the fourth quarter of 2017.~~ See Note 12 to the consolidated financial statements of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2016~~2018 for further ~~discussion regarding the nuclear generating plants.~~information. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2016 and Nuclear Power Operations included in Item 2 of NSP-Minnesota’s Quarterly Report~~

~~on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017,~~2018 appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated ~~herein~~ by reference.

Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately ~~12 percent~~49% of its ~~2017~~remaining 2019 and approximately ~~59 percent~~50% of its 2018 enriched nuclear material requirements from sources that could be impacted by events in Ukraine and sanctions against Russia. Alternate potential sources are expected to provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply to ensure that plant availability and reliability will not be negatively impacted in the near-term. Long-term, through 2024, NSP-Minnesota is scheduled to take delivery of approximately 31 percent of its average2020 enriched nuclear material requirements from sources that could be impacted by events in Ukraine and extended sanctions against Russia. Long-term, through 2024, NSP-Minnesota is ~~closely following~~scheduled to take delivery of approximately 35% of its average enriched nuclear material requirements from these sources. Alternate potential sources provide the ~~progression of these events and will~~flexibility to manage NSP-Minnesota’s nuclear fuel supply. NSP-Minnesota periodically ~~assess~~assesses if further actions are required to assure a secure supply of enriched nuclear material.

~~Separately, NSP-Minnesota has enriched~~Disruptions in third party nuclear fuel materials in process with Westinghouse Electric Corporation (Westinghouse). Westinghouse filed for Chapter 11 bankruptcy protection in March 2017. NSP-Minnesota owns materials in Westinghouse’s inventory and hassupply contracts in place under which Westinghouse will provide certain services during an upcoming outage at PI. Westinghouse provided nuclear fuel assemblies for the upcoming PI outage under the current nuclear fuel fabrication contract. Westinghouse has indicated its intentiondue to ~~continue to perform under the arrangements. Based on Westinghouse’s stated intent and the interim financing secured to fund its on-going operations, NSP-Minnesota does~~bankruptcies or change of contract assignments have not ~~expect the bankruptcy to~~ materially ~~impact~~impacted NSP-Minnesota’s operational or financial performance.

~~Summary of Recent Federal Regulatory Developments~~Environmental Matters

~~FERC~~

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

~~FERC ROE Policy~~ — In June ~~2014,~~2019, the ~~FERC adopted a two-step ROE methodology for electric utilities in an order~~EPA issued ~~in a complaint proceeding involving New England Transmission Owners (NETOs).~~the final ACE rule to replace the Obama-era Clean Power Plan. The ~~issue~~final ACE rule may require implementation of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including two ROE complaints involving the MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. In April 2017, the D.C. Circuit vacated and remanded the June 2014 ROE order. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for the NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. The FERC has yet to act on the D.C. Circuit’s decision. See Note 5 to the consolidated financial statements for discussionheat rate improvement projects at some of ~~the D.C. Circuit’s decision and the impact on the MISO ROE Complaints.~~

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

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

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

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

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

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

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

~~Minnesota State Right-Of-First Refusal (ROFR) Statute Complaint~~ —In September 2017, LSP Transmission Holdings, LLC filed a complaint in the U.S. District Court in Minnesota against the Minnesota Attorney General, the MPUC and the DOC. The complaint was in response to NSP-Minnesota and ITC Midwest, LLC being assigned by MISO to jointly own a new 345 kilovolt transmission line that is planned to run from NSP-Minnesota’s Wilmarth Substation near Mankato, Minn. to ITC Midwest’s Huntley Substation in Minnesota south of Winnebago, Minn. The line is estimated to cost $108 million. The project was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenges the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies are expected to answer the complaint in November 2017. NSP-Minnesota expects to intervene in the case. The timing and outcome of the litigation is uncertain.

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

Item 4—CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.

As of ~~Sept.~~June 30, ~~2017,~~2019, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

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

Part II — OTHER INFORMATION

~~Part II~~ — ~~OTHER INFORMATION~~

Item 1—~~LEGAL PROCEEDINGS~~

Legal Proceedings

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

~~Additional Information~~

See Note 69 to the consolidated financial statements ~~for further discussion of legal claims~~ and ~~environmental proceedings. See~~ Part I Item 2 ~~and Note 5 to the consolidated financial statements~~ for ~~a discussion of proceedings involving utility rates and other regulatory matters.~~further information.

Item 1A — RISK FACTORS

NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, ~~2016,~~2018, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form ~~10-K.~~10-K.

* Indicates incorporation by reference

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

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. 27, 2017~~Aug. 1, 2019	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

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


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016			2019			2018			2019			2018
Operating revenues
Electric, non-affiliates	$	1,167,447		$	1,161,259		$	3,083,182		$	2,973,350		$	981.0		$	979.0		$	1,939.6		$	1,924.3
Electric, affiliates	123,524			121,315			366,598			359,338			116.2			117.4			236.3			234.4
Natural gas	57,442			55,519			356,631			314,020			79.4			83.1			343.5			324.5
Other	7,366			7,286			21,448			21,404			8.4			8.2			16.1			15.3
Total operating revenues	1,355,779			1,345,379			3,827,859			3,668,112			1,185.0			1,187.7			2,535.5			2,498.5

Operating expenses
Electric fuel and purchased power	435,003			435,560			1,215,071			1,148,818			404.4			416.5			796.3			824.3
Cost of natural gas sold and transported	20,723			19,105			198,968			163,608			33.9			36.8			208.3			192.1
Cost of sales — other	4,313			4,898			13,085			14,185			5.4			4.6			10.6			8.9
Operating and maintenance expenses	288,770			315,298			909,381			954,334			305.5			309.2			617.4			601.5
Conservation program expenses	31,674			23,926			92,238			67,424			25.6			27.5			58.1			58.3
Depreciation and amortization	176,739			149,408			522,070			442,649			197.5			178.7			395.1			360.1
Taxes (other than income taxes)	62,220			49,763			191,989			186,100			65.4			64.3			135.0			131.8
Total operating expenses	1,019,442			997,958			3,142,802			2,977,118			1,037.7			1,037.6			2,220.8			2,177.0

Operating income	336,337			347,421			685,057			690,994			147.3			150.1			314.7			321.5

Other income (expense), net	2,120			(439		)	3,750			1,834
Other (expense) income, net													(1.3		)	(2.2		)	0.2			(2.0		)

Allowance for funds used during construction — equity	10,683			7,983			23,391			21,011			5.5			6.9			10.6			13.6

Interest charges and financing costs
Interest charges — includes other financing costs of $1,845, $1,822, $5,437 and $5,325, respectively	57,577			57,859			172,548			168,010
Interest charges — includes other financing costs of $1.8, $1.8, $3.6 and $3.6, respectively													56.9			56.8			114.1			114.1
Allowance for funds used during construction — debt	(5,383		)	(3,591		)	(11,909		)	(9,575		)	(3.0		)	(3.4		)	(5.5		)	(6.8		)
Total interest charges and financing costs	52,194			54,268			160,639			158,435			53.9			53.4			108.6			107.3

Income before income taxes	296,946			300,697			551,559			555,404			97.6			101.4			216.9			225.8
Income taxes	67,943			94,145			140,728			176,047			1.7			9.0			7.8			21.7
Net income	$	229,003		$	206,552		$	410,831		$	379,357		$	95.9		$	92.4		$	209.1		$	204.1


	Nine Months Ended Sept. 30,						Six Months Ended June 30,
	2017			2016			2019			2018
Operating activities
Net income	$	410,831		$	379,357		$	209.1		$	204.1
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	526,784			447,284			398.1			363.3
Nuclear fuel amortization	87,654			89,475			58.1			62.3
Deferred income taxes	98,125			129,410			(5.8		)	41.2
Amortization of investment tax credits	(1,241		)	(1,260		)	(0.7		)	(0.8		)
Allowance for equity funds used during construction	(23,391		)	(21,011		)	(10.6		)	(13.6		)
Net realized and unrealized hedging and derivative transactions	(2,703		)	2,873			6.5			(1.5		)
Other, net	(1,072		)	—
Changes in operating assets and liabilities:
Accounts receivable	(14,677		)	(46,294		)	55.9			(16.0		)
Accrued unbilled revenues	33,465			26,660			37.8			31.4
Inventories	(4,265		)	5,709			17.5			44.1
Other current assets	35,591			24,431			(23.7		)	59.7
Accounts payable	(34,275		)	19,736			(32.0		)	(31.7		)
Net regulatory assets and liabilities	(15,467		)	57,452			(100.4		)	43.8
Other current liabilities	(73,898		)	(3,947		)	(76.6		)	(105.7		)
Pension and other employee benefit obligations	(55,548		)	(42,447		)	(46.7		)	(59.4		)
Change in other noncurrent assets	(3,585		)	(8,862		)
Change in other noncurrent liabilities	(30,704		)	(17,084		)
Other, net							(12.5		)	(17.7		)
Net cash provided by operating activities	931,624			1,041,482			474.0			603.5

Investing activities
Utility capital/construction expenditures	(696,857		)	(833,845		)	(522.7		)	(426.2		)
Allowance for equity funds used during construction	23,391			21,011
Purchases investment securities	(965,086		)	(349,717		)
Purchases of investment securities							(488.1		)	(367.2		)
Proceeds from the sale of investment securities	948,558			327,378			477.9			357.0
Investments in utility money pool arrangement	(122,000		)	(492,000		)	(219.0		)	(627.0		)
Repayments from utility money pool arrangement	122,000			441,000			219.0			627.0
Other, net	(3,463		)	(1,262		)	(0.4		)	(2.1		)
Net cash used in investing activities	(693,457		)	(887,435		)	(533.3		)	(438.5		)

Financing activities
Repayments of short-term borrowings, net	(85,000		)	(223,000		)
Proceeds from (repayments of) short-term borrowings, net							44.0			(20.0		)
Borrowings under utility money pool arrangement	516,000			424,000			99.0			131.0
Repayments under utility money pool arrangement	(466,000		)	(424,000		)	(49.0		)	(154.0		)
Proceeds from issuance of long-term debt	586,264			342,570
Repayments of long-term debt, including reacquisition premiums	(507,865		)	(11		)
Capital contributions from parent	123,247			96,628			134.9			49.6
Dividends paid to parent	(418,133		)	(306,209		)	(177.4		)	(183.3		)
Net cash used in financing activities	(251,487		)	(90,022		)
Net cash provided by (used in) financing activities							51.5			(176.7		)

Net change in cash and cash equivalents	(13,320		)	64,025			(7.8		)	(11.7		)
Cash and cash equivalents at beginning of period	47,595			42,605			50.0			43.8
Cash and cash equivalents at end of period	$	34,275		$	106,630		$	42.2		$	32.1

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(177,336	)	$	(169,382	)	$	(105.5	)	$	(101.0	)
Cash paid for income taxes, net	(60,911		)	(14,279		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	47,261		$	72,889
Cash (paid) received for income taxes, net							(42.6		)	64.2
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions							$	107.8		$	50.3
Inventory transfers to property, plant and equipment							9.6			10.4
Operating lease right-of-use assets							628.5			—
Allowance for equity funds used during construction							10.6			13.7


	Sept. 30, 2017			Dec. 31, 2016			June 30, 2019			Dec. 31, 2018
Assets
Current assets
Cash and cash equivalents	$	34,275		$	47,595		$	42.2		$	50.0
Accounts receivable, net	344,528			329,481			320.4			380.9
Accounts receivable from affiliates	19,989			49,355			20.4			11.0
Accrued unbilled revenues	226,125			259,590			232.5			270.3
Inventories	349,578			345,192			272.4			299.4
Regulatory assets	253,876			186,266			299.1			280.3
Derivative instruments	47,177			22,028			42.2			25.8
Prepaid taxes							21.3			—
Prepayments and other	65,292			98,006			29.3			28.9
Total current assets	1,340,840			1,337,513			1,279.8			1,346.6

Property, plant and equipment, net	13,360,494			13,300,793
Property, plant and equipment							13,730.4			13,541.7

Other assets
Nuclear decommissioning fund and other investments	2,105,741			1,905,059			2,354.1			2,107.2
Regulatory assets	1,187,195			1,245,151			1,248.9			1,454.1
Derivative instruments	28,520			24,678			6.6			17.0
Operating lease right-of-use assets							601.5			—
Other	13,217			9,086			9.5			3.3
Total other assets	3,334,673			3,183,974			4,220.6			3,581.6
Total assets	$	18,036,007		$	17,822,280		$	19,230.8		$	18,469.9

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	7		$	10
Short-term debt	—			85,000			$	194.0		$	150.0
Borrowings under utility money pool arrangement	50,000			—			50.0			—
Accounts payable	292,970			371,589			394.0			393.6
Accounts payable to affiliates	50,745			59,216			73.0			109.7
Regulatory liabilities	98,587			60,779			164.0			262.4
Taxes accrued	235,999			241,100			186.7			230.1
Accrued interest	52,115			71,012			66.6			67.2
Dividends payable to parent	88,461			89,428			95.3			82.7
Derivative instruments	18,045			16,606			24.2			16.5
Customer deposits	103,549			110,244			54.3			53.7
Other	152,919			150,244			225.3			154.8
Total current liabilities	1,143,397			1,255,228			1,527.4			1,520.7

Deferred credits and other liabilities
Deferred income taxes	2,947,022			2,788,752			1,758.8			1,682.4
Deferred investment tax credits	22,935			24,175			20.4			21.1
Regulatory liabilities	491,385			489,825			1,962.1			1,984.7
Asset retirement obligations	2,543,497			2,452,567			2,231.5			2,177.9
Derivative instruments	105,963			116,804			105.6			112.2
Pension and employee benefit obligations	313,772			368,922			260.3			305.1
Operating lease liabilities							566.3			—
Other	94,372			127,283			91.6			155.5
Total deferred credits and other liabilities	6,518,946			6,368,328			6,996.6			6,438.9

Commitments and contingencies
Capitalization
Long-term debt	4,932,970			4,843,155			4,939.3			4,937.2
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively	10			10
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at June 30, 2019 and Dec. 31, 2018, respectively							—			—
Additional paid in capital	3,525,612			3,435,096			3,799.0			3,624.2
Retained earnings	1,934,911			1,941,246			1,991.2			1,972.0
Accumulated other comprehensive loss	(19,839		)	(20,783		)	(22.7		)	(23.1		)
Total common stockholder’s equity	5,440,694			5,355,569			5,767.5			5,573.1
Total liabilities and equity	$	18,036,007		$	17,822,280		$	19,230.8		$	18,469.9



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



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



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



(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	250		$	250
Amount outstanding at period end	50			—
Average amount outstanding	50			16
Maximum amount outstanding	116			225
Weighted average interest rate, computed on a daily basis	1.11		%	0.69		%
Weighted average interest rate at period end	1.11			N/A


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




	Nine Months Ended Sept. 30, 2017
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	1,304		^(a)	$	—			$	—
Vehicle fuel and other commodity	81		—			(16		)	^(b)	—				—
Total	$	81	$	—		$	1,288			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	8,092		^(c)
Electric commodity	—		17,444			—				(9,293		)	^(d)	—
Natural gas commodity	—		(1,010		)	—				698			^(e)	(945		)	^(e)
Total	$	—	$	16,434		$	—			$	(8,595	)		$	7,147




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



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


^(b)	During 2006, ~~NSP-Minnesota~~Xcel Energy 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.



612	330-5500



	Dec. 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	12,053	$	8,651	$	—	$	20,704	$	(15,500	)	$	5,204
Electric commodity	—		—		15,997		15,997		(677		)	15,320
Natural gas commodity	—		912		—		912		—			912
Total current derivative assets	$	12,053	$	9,563	$	15,997	$	37,613	$	(16,177	)	21,436
PPAs ^(a)												592
Current derivative instruments												$	22,028
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	100	$	31,029	$	—	$	31,129	$	(7,323	)	$	23,806
Total noncurrent derivative assets	$	100	$	31,029	$	—	$	31,129	$	(7,323	)	23,806
PPAs ^(a)												872
Noncurrent derivative instruments												$	24,678


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


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


^(b)	Included in the computation of net periodic pension and postretirement benefit costs.



	Three Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at July 1	$	(17,775	)	$	105	$	(2,609	)	$	(20,279	)
Other comprehensive income before reclassifications	22			—		—			22
Losses reclassified from net accumulated other comprehensive loss	379			—		39			418
Net current period other comprehensive income	401			—		39			440
Accumulated other comprehensive (loss) income at Sept. 30	$	(17,374	)	$	105	$	(2,570	)	$	(19,839	)



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



(Millions of Dollars)	2017 vs. 2016
Purchased natural gas adjustment clause recovery	$	34
Conservation program revenue, offset by expenses	4
Retail sales growth, excluding weather impact	3
Infrastructure and integrity riders	3
Other, net	(1		)
Total increase in natural gas revenues	$	43



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



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

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



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed ~~Northern States Power Co. (a Minnesota corporation)~~NSP-Minnesota on Aug. 21, 2000) ~~(Exhibit 3.01 to~~	NSP-Minnesota Form 10-12G ~~(file no. 000-31709)~~ dated Oct. 5, ~~2000).~~2000	000-31709	3.01
3.02*	By-Laws of ~~Northern States Power Co. (a Minnesota corporation)~~NSP-Minnesota as Amended and Restated on ~~Sept. 26, 2013 (Exhibit 3.02 to~~Jan. 25, 2019	NSP-Minnesota Form ~~10-Q/A~~10-K for the ~~quarter~~year ended ~~Sept. 30, 2013 (file no. 000-31387)).~~Dec. 31, 2018	001-31387	3.02
~~4.01~~10.01*	~~Supplemental Indenture~~Third Amended and Restated Credit Agreement, dated as of ~~Sept. 1, 2017 between~~June 7, 2019 among NSP-Minnesota, ~~and The~~as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of ~~New York Mellon Trust Company,~~America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as ~~successor trustee, creating $600 million principal amount of 3.60 percent First Mortgage Bonds, Series due Sept. 15, 2047 (Exhibit 4.01 to~~Documentation Agents	Xcel Energy Inc. Form 8-K dated ~~Sept. 13, 2017 (file no. 001-31387)).~~June 7, 2019	001-03034	99.02
~~10.1~~*+	Fourth Amendment to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.1 to Form 10-Q of Xcel Energy for the quarter ended Sept. 30, 2017 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
~~99.01~~	~~Statement pursuant to Private Securities Litigation Reform Act of 1995.~~
101	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended ~~Sept.~~June 30, ~~2017~~2019 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.

(Amounts in Millions) ^(a)(b)

June 30, 2019

Dec. 31, 2018

MWh of electricity

MMBtu of natural gas