10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2018

or

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

001-31387	41-1967505
(Commission File Number)	(I.R.S. Employer Identification No.)

(Registrant, State of Incorporation or Organization, Address of Principal Executive Officers and Telephone Number)

Northern States Power Company

(a Minnesota corporation)

414 Nicollet Mall

Minneapolis, MN 55401

612-330-5500

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes ¨ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes x No

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ¨ Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ 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 Act). ¨ Yes x No

As of Feb. 22, 2019, 1,000,000 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.

Northern States Power Company meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

TABLE OF CONTENTS

Index

PART I
Item 1 — Business	3
ABBREVIATIONS AND INDUSTRY TERMS	3
FORWARD-LOOKING STATEMENTS	4
WHERE TO FIND MORE INFORMATION	4
COMPANY OVERVIEW	4
ELECTRIC UTILITY OPERATIONS	5
Electric Operating Statistics	5
Energy Sources	6
Capacity and Demand	7
Public Utility Regulation	7
Energy Sources and Transmission Service Provider	7
Nuclear Power Operations and Waste Disposal	8
Wholesale and Commodity Marketing Operations	8
NATURAL GAS UTILITY OPERATIONS	8
Natural Gas Operating Statistics	9
Capability and Demand	9
Natural Gas Supply and Costs	9
Public Utility Regulation	9
GENERAL	10
ENVIRONMENTAL MATTERS	10
EMPLOYEES	10
Item 1A — Risk Factors	10
Item 1B — Unresolved Staff Comments	16
Item 2 — Properties	16
Item 3 — Legal Proceedings	16
Item 4 — Mine Safety Disclosures	16
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6 — Selected Financial Data	16
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	19
Item 8 — Financial Statements and Supplementary Data	20
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	50
Item 9A — Controls and Procedures	50
Item 9B — Other Information	50
PART III
Item 10 — Directors, Executive Officers and Corporate Governance	50
Item 11 — Executive Compensation	50
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 13 — Certain Relationships and Related Transactions, and Director Independence	50
Item 14 — Principal Accountant Fees and Services	50
PART IV
Item 15 — Exhibits, Financial Statement Schedules	51
Item 16 — Form 10-K Summary	53
SIGNATURES	54

This Form 10-K is filed by NSP-Minnesota. NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.

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PART I

Item l — Business

ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSPM	NSP-Minnesota
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP System	The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
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
DOE	United States Department of Energy
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPUC	Minnesota Public Utilities Commission
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
NRC	Nuclear Regulatory Commission
OAG	Minnesota Office of the Attorney General
PHMSA	Pipeline and Hazardous Materials Safety Administration
SDPUC	South Dakota Public Utilities Commission
SEC	Securities and Exchange Commission
Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
EIR	Environmental improvement rider
FCA	Fuel clause adjustment
GUIC	Gas utility infrastructure cost rider
PGA	Purchased gas adjustment
RDF	Renewable development fund
RER	Renewable energy rider
RES	Renewable energy standard
SEP	State energy policy rider
TCR	Transmission cost recovery adjustment
Other
AFUDC	Allowance for funds used during construction
ALJ	Administrative law judge
ARAM	Average rate assumption method
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
C&I	Commercial and Industrial
CAPM	Capital Asset Pricing Model
CapX2020	Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CCR	Coal combustion residuals
CO2	Carbon dioxide

Corps	U.S. Army Corps of Engineers
CPP	Clean Power Plan
CWA	Clean Water Act
CWIP	Construction work in progress
DCF	Discounted Cash Flows
ELG	Effluent limitations guidelines
EMANI	European Mutual Association for Nuclear Insurance
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GE	General Electric
GHG	Greenhouse gas
IPP	Independent power producing entity
IRP	Integrated Resource Plan
ISFSI	Independent spent fuel storage installation
ITC	Investment tax credit
LLW	Low-level radioactive waste
LNG	Liquefied natural gas
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investor Services
Native load	Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract.
NAV	Net asset value
NEIL	Nuclear Electric Insurance Ltd.
NETO	New England Transmission Owners
NOL	Net operating loss
O&M	Operating and maintenance
Paris Agreement	Establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”)
PI	Prairie Island nuclear generating plant
Pipeline Safety Act	Pipeline Safety, Regulatory Certainty, and Job Creation Act
PPA	Purchased power agreement
PTC	Production tax credit
REC	Renewable energy credit
ROE	Return on equity
RTO	Regional Transmission Organization
SAB	Staff Accounting Bulletin
SAB 118	Income Tax Accounting Implications of the Tax Cuts and Jobs Act
SERP	Supplemental executive retirement plan
SMMPA	Southern Minnesota Municipal Power Agency
Standard & Poor’s	Standard & Poor’s Ratings Services
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
VaR	Value at Risk
VIE	Variable interest entity
Westinghouse	Westinghouse Electric Corporation
Measurements
Bcf	Billion cubic feet
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

3

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 Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2018 (including risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), 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.

Where To Find More Information

NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov.

COMPANY OVERVIEW

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota conducts business in Minnesota, North Dakota and South Dakota and has electric operations in all three states including the generation, purchase, transmission, distribution and sale of electricity as managed on the NSP System. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota.

	NSP-Minnesota
	Electric customers	1.5 million
	Natural gas customers	0.5 million
	Consolidated earnings contribution	35% to 45%
	Total assets	$18.5 billion
	Electric generating capacity	7,530 MW
	Gas storage capacity	14.7 Bcf

4

ELECTRIC UTILITY OPERATIONS

Electric Operating Statistics

	Year Ended Dec. 31
	2018			2017			2016
Electric sales (Millions of KWh)
Residential	10,476			9,900			10,107
Large C&I	8,877			8,829			8,890
Small C&I	15,323			15,104			15,377
Public authorities and other	224			225			248
Total retail	34,900			34,058			34,622
Sales for resale	6,736			5,739			5,333
Total energy sold	41,636			39,797			39,955
Number of customers at end of period
Residential	1,318,095			1,306,825			1,296,852
Large C&I	558			557			555
Small C&I	157,636			156,386			155,865
Public authorities and other	8,124			7,774			7,368
Total retail	1,484,413			1,471,542			1,460,640
Wholesale	11			8			10
Total customers	1,484,424			1,471,550			1,460,650
Electric revenues (Millions of Dollars)
Residential	$	1,364.9		$	1,320.5		$	1,310.3
Large C&I	682.2			690.2			686.2
Small C&I	1,500.6			1,560.3			1,513.0
Public authorities and other	35.4			35.5			35.4
Total retail	3,583.1			3,606.5			3,544.9
Wholesale	193.4			161.6			124.9
Interchange revenues from NSP-Wisconsin	473.7			490.2			475.5
Other electric revenues	257.8			283.4			259.3
Total electric revenues	$	4,508.0		$	4,541.7		$	4,404.6
KWh sales per retail customer	23,511			23,144			23,703
Revenue per retail customer	$	2,414		$	2,451		$	2,427
Residential revenue per KWh		13.03	¢		13.34	¢		12.96	¢
Large C&I revenue per KWh	7.69			7.82			7.72
Small C&I revenue per KWh	9.79			10.33			9.84
Total retail revenue per KWh	10.27			10.59			10.24
Wholesale revenue per KWh	2.87			2.82			2.34

5

Energy Sources 2018

*Distributed generation from the Solar*Rewards^® program is not included (approximately 32 million KWh for 2018).

Energy Source Statistics

In 2018, of the NSP System’s total energy generation, 77% was owned and 23% was purchased. In 2017, 75% was owned and 25% was purchased.

Renewable Sources

NSP-Minnesota’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2018, NSP-Minnesota was in compliance with its applicable renewable portfolio standards. Renewable percentages will vary year over year based on local weather, system demand and transmission constraints.

NSP System

Renewable energy as a percentage of the NSP System’s total:

	2018		2017
Wind	16.4	%	18.3	%
Hydroelectric	5.8		6.3
Biomass and solar	4.8		4.2
Renewable	27.0	%	28.8	%

Wind —The NSP System has more than 130 PPAs ranging from under one MW to more than 200 MW. The NSP System owns and operates five wind farms with 840 MW, net, of capacity.

• The NSP System had approximately 2,550 MW and 2,600 MW of wind energy on its system at the end of 2018 and 2017, respectively.

• Average cost per MWh of wind energy under existing PPAs was approximately $44 for 2018 and 2017.

• Average cost per MWh of wind energy from owned generation was approximately $37 and $42 for 2018 and 2017, respectively.

Non-Renewable Sources

Delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation and the percentage of total fuel requirements represented by each category of fuel:

	Coal (a)				Nuclear				Natural Gas
	Cost		Percent		Cost		Percent		Cost		Percent
2018	$	2.13	42	%	$	0.80	45	%	$	3.87	13	%
2017	2.08		45		0.78		45		4.10		10

^(a)  Includes refuse-derived fuel and wood.

Weighted average cost per MMBtu of all fuels for owned electric generation was $1.78 in 2018 and $1.72 in 2017.

See Items 1A and 7 for further information.

Coal — Inventory maintained (in days):

Normal	Dec. 31, 2018 Actual	Dec. 31, 2017 Actual (a)
35 - 50	47	53

^(a)  Milder weather, purchase commitments and low power and natural gas prices impacted coal inventory levels.

Coal requirements (in million tons) was 7.8 in 2018 and 8.0 in 2017. Coal supply as a percentage of requirements for 2019 is 8.4 million tons or 76% of contracted coal supply. The general coal purchasing objective is to contract for approximately 75% of year one requirements, 40% of year two requirements and 20% of year three requirements. Increase in estimated million tons was due to lower delivered coal prices at Sherco in January 2019, combined with higher future forecasted gas prices for 2019 (higher burn forecast).

Contracted coal transportation as a percentage of requirements in 2019 and 2020 is 100%.

Natural Gas — Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.

Contracts and commitments at Dec. 31:

(Millions of Dollars)	Gas Supply		Gas Transportation and Storage (a)
2018	$	—	$	406
2017	—		398
Year of Expiration	N/A		2020 - 2037

^(a)  For incremental supplies, there are limited on-site fuel storage facilities, with a primary reliance on the spot market.

Nuclear — NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium concentrates, conversion services and enrichment services with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions due to geographical and world political issues.

• Current nuclear fuel supply contracts cover 100% of uranium concentrates requirements through 2021 and approximately 51% of the requirements for 2022 - 2033;

6

• Current contracts for conversion services cover 100% of the requirements through 2021 and approximately 43% of the requirements for 2022 - 2033; and

• Current enrichment service contracts cover 100% of the requirements through 2025 and approximately 19% of the requirements for 2026 - 2033.

Fabrication services for Monticello and PI are 100% committed through 2030 and 2027, respectively. 

NSP-Minnesota expects sufficient uranium concentrates, conversion services and enrichment services to be available for the requirements of its nuclear generating plants. Some exposure to market price volatility will remain due to index-based pricing structures contained in supply contracts.

See Item 7 for further information.

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for the last two years, is as follows:

System Peak Demand (in MW)
2018		2017
8,927	June 29	8,546	July 17

The peak demand typically occurs in the summer. The increase in peak load from 2017 to 2018 is partly due to warmer weather in 2018.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC. The MPUC also has regulatory authority over security issuances, certain property transfers, mergers, dispositions of assets and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s IRPs for meeting future energy needs. In addition, MPUC certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV that will be located within the state. The NDPSC and SDPUC have regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subject to the jurisdiction of the FERC for its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.

NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and MISO wholesale market. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.

Fuel, Purchased Energy and Conservation Cost-Recovery

Mechanisms —

• CIP rider — Recovers the costs of conservation and demand-side management programs.

• EIR — Recovers the costs of environmental improvement projects.

• RDF — Allocates money collected from retail customers to support emerging renewable energy projects and technologies.

• RES — Recovers the cost of renewable generation in Minnesota.

• RER — Recovers the cost of renewable generation in North Dakota.

• SEP — Recovers costs related to various energy policies approved by the Minnesota legislature.

• TCR — Recovers costs associated with investments in electric transmission and distribution grid modernization costs.

• Infrastructure rider — Recovers costs for investments in generation and incremental property taxes in South Dakota.

NSP-Minnesota’s retail electric rates in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments to recover changes in prudently incurred costs of fuel related items and purchased energy. Capacity costs are recovered through base rates and are not recovered through the FCA. Costs associated with MISO are generally recovered through either the FCA or base rates.

In 2017, the MPUC voted to change the FCA process in Minnesota. Under the new process, each month utilities would collect amounts equal to the baseline cost of energy set at the start of the plan year (base would be reset annually). Monthly variations to the baseline costs would be tracked and netted over a 12-month period. Utilities would issue refunds above the baseline costs, and could seek recovery of any overage. Recently, the MPUC delayed implementation until 2020.

Minnesota state law requires NSP-Minnesota to invest 2% of its state electric revenues and 0.5% of its state gas revenues in CIP. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.

Energy Sources and Transmission Service Provider

NSP-Minnesota expects to use power plants, power purchases, CIP/DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.

Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.

Purchased Transmission Services— NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.

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

In April 2018, the MPUC approved NSP-Minnesota’s petition to build and own the Dakota Range, a 300 MW wind project in South Dakota. NSP-Minnesota’s capital investment for the Dakota Range is expected to be approximately $350 million and placed in service in 2021.

In December 2018, the NDPSC approved a settlement agreement for these wind development projects.

7

PPA Terminations and Amendments — In June 2018, NSP-Minnesota terminated the Benson and Laurentian PPAs, and purchased the Benson biomass facility. As a result, a $103 million regulatory asset was recognized for the costs of the Benson transaction. For Laurentian, a regulatory asset of $109 million was recognized for annual payments/obligations. Regulatory approvals provide for recovery of the Benson regulatory asset over 10 years, and Laurentian termination payments as they occur (over six years). Termination of the PPAs is expected to save customers over $600 million 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. Docket remains under consideration by the NDPSC.

Minnesota State ROFR Statute Complaint — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, the MPUC and the DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line from near Mankato, Minnesota to Winnebago, Minnesota. The project was estimated by MISO to cost $108 million. The project was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenged the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. In June 2018, the Minnesota District Court granted the defendants’ motions to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. It is uncertain when a decision will be rendered.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes which are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in a plant.

NRC Regulation — The NRC regulates nuclear operations. The costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs in customer rates, and expects future compliance costs will continue to be recoverable.

LLW Disposal — LLW from NSP-Minnesota’s Monticello and PI nuclear plants is currently disposed at the Clive facility located in Utah and the Waste Control Specialists facility located in Texas. If off-site LLW disposal facilities become unavailable, NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives.

High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility.

The federal government has been evaluating a nuclear geologic repository at Yucca Mountain, Nevada for many years. At this time, there are no definitive plans for a permanent federal storage site at Yucca Mountain or any other site.

Review of PI Costs —As part of NSP-Minnesota’s 2016 multi-year electric rate case and IRP, the MPUC ordered an investigation into NSP-Minnesota’s PI nuclear investments. The issue was resolved as part of the 2016 multi-year electric rate case settlement. In November 2018, the DOC issued a final report, in which no cost disallowances were recommended.

Nuclear Spent Fuel Storage—NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.

In 2013, NSP-Minnesota’s Monticello nuclear generating plant loaded and placed five storage canisters (canisters #11-15) in the ISFSI and a sixth canister (canister #16) was loaded but remained in the plant pending resolution of weld inspection issues. Successful pressure and leak testing demonstrated the safety and integrity of all six canisters involved. NSP-Minnesota took several actions to assure compliance with the NRC’s regulations and Monticello’s storage license. The NRC has approved NSP-Minnesota’s compliance plan for all canisters.

NSP-Minnesota intends to seek recovery of these costs in a future regulatory proceeding. No public safety issues have been raised, or are believed to exist, in this matter.

See Note 10 to the consolidated financial statements for further information.

Wholesale and Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.

8

NATURAL GAS UTILITY OPERATIONS

Natural Gas Operating Statistics

	Year Ended Dec. 31
	2018		2017		2016
Natural gas deliveries (Thousands of MMBtu)
Residential	43,876		38,365		35,592
C&I	45,909		41,047		37,824
Total retail	89,785		79,412		73,416
Transportation and other	13,101		13,109		11,189
Total deliveries	102,886		92,521		84,605
Number of customers at end of period
Residential	475,441		470,255		465,745
C&I	44,217		43,859		43,553
Total retail	519,658		514,114		509,298
Transportation and other	26		26		25
Total customers	519,684		514,140		509,323
Natural gas revenues (Millions of Dollars)
Residential	$	320.0	$	287.5	$	261.6
C&I	248.8		221.6		194.0
Total retail	568.8		509.1		455.6
Transportation and other	14.3		22.8		11.8
Total natural gas revenues	$	583.1	$	531.9	$	467.4
MMBtu sales per retail customer	172.78		154.46		144.15
Revenue per retail customer	$	1,095	$	990	$	895
Residential revenue per MMBtu	7.29		7.49		7.35
C&I revenue per MMBtu	5.42		5.40		5.13
Transportation and other revenue per MMBtu	1.09		1.74		1.05

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).

Maximum daily send-out (firm and interruptible) and occurrence date:

2018			2017
MMBtu		Date	MMBtu	Date
786,751	(a)	Jan. 12	893,062	Dec. 26

^(a)  Decrease in MMBtu output due to milder winter temperatures in 2018.

Natural gas is purchased from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 645,171 MMBtu per day.

NSP-Minnesota contracts with providers of underground natural gas storage services. Agreements provided storage of winter natural gas requirements and peak day firm requirements of 24% and 29% in 2018, respectively.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio which provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Minnesota conducts natural gas price hedging activities approved by their respective state commissions.

Average delivered cost per MMBtu of natural gas for regulated retail distribution was $4.03 and $3.89 in 2018 and 2017, respectively.

NSP-Minnesota has natural gas supply, transportation, and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery. As of Dec. 31, 2018, NSP-Minnesota was committed to approximately $437 million of obligations under contracts, which expire in various years from 2019 - 2033.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s retail natural gas operations are regulated by the MPUC and NDPSC. The MPUC has regulatory authority over security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. The MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting future energy needs. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Minnesota is also subject to the DOT, Minnesota Office of Pipeline Safety, NDPSC and SDPUC for pipeline safety compliance.

Purchased Gas and Conservation Cost-Recovery Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas, transportation and storage service. The annual difference between the natural gas cost revenues collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent 12-month period.

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NSP-Minnesota also recovers costs associated with transmission and distribution pipeline integrity management programs through its GUIC rider. Costs recoverable under the GUIC rider include funding for pipeline assessments as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs.

GENERAL

Seasonality

Demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, NSP-Minnesota’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

See Item 7 for further information.

Competition

NSP-Minnesota is a vertically integrated utility, subject to traditional cost-of-service regulation by state public utilities commissions. NSP-Minnesota is subject to public policies that promote competition and development of energy markets. NSP-Minnesota’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.

Customers have the opportunity to supply their own power with distributed generation including, but not limited to, solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states, including Minnesota, have policies designed to promote the development of solar and other distributed energy resources through incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to NSP-Minnesota’s electric service business.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, NSP-Minnesota and its wholesale customers can purchase generation resources from competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load.

FERC Order No. 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.

NSP-Minnesota has franchise agreements with cities subject to periodic renewal, however, a city could seek alternative means to access electric power or gas, such as municipalization.

While facing these challenges, NSP-Minnesota believes its rates and services are competitive with the alternatives currently available.

ENVIRONMENTAL MATTERS

NSP-Minnesota’s facilities are regulated by federal and state environmental agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. NSP-Minnesota has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.

NSP-Minnesota’s facilities have been designed and constructed to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon NSP-Minnesota’s operations. NSP-Minnesota will likely be required to incur capital expenditures in the future to comply with requirements for remediation of MGP and other legacy sites. The scope and timing of these expenditures cannot be determined until more information is obtained regarding the need for remediation at legacy sites.

NSP-Minnesota must comply with emission budgets that require the purchase of emission allowances from other utilities.

There are significant present and future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. NSP-Minnesota has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If future environmental regulations do not provide credit for the investments NSP-Minnesota has already made or if they require additional initiatives or emission reductions, substantial costs may be incurred.

The EPA , as an alternative to the CPP, has proposed a new regulation that, if adopted, would require implementation of heat rate improvement projects at our coal-fired power plants. It is not known what those costs might be until a final rule is adopted and state plans are developed to implement a final regulation. NSP-Minnesota believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates.

NSP-Minnesota is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. Starting in 2011, NSP-Minnesota began reporting GHG emissions under the EPA’s mandatory GHG Reporting Program.

EMPLOYEES

As of Dec. 31, 2018, NSP-Minnesota had 3,271 full-time employees and seven part-time employees, of which 2,064 were covered under collective-bargaining agreements.

Item 1A — Risk Factors

Xcel Energy, which includes NSP-Minnesota, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC.

Oversight of Risk and Related Processes

A key accountability of the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective process for doing so. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and analysis occurs formally through a key risk assessment conducted by senior management, the financial disclosure process, hazard risk management procedures and internal auditing and compliance with financial and operational controls.

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Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing NSP-Minnesota’s strategy. The business planning process also identifies areas in which there is a potential for a business area to assume inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.

At a threshold level, NSP-Minnesota has a robust compliance program and promotes a culture of compliance, including tone at the top. The process for risk mitigation includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management to mitigate the risks inherent in the implementation of strategy. Building on this culture of compliance, management further mitigates risks through formal risk management structures, including management councils, risk committees and services of corporate areas such as internal audit, corporate controller and legal.

Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors which provides information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Oversight of cybersecurity risks by the Operations, Nuclear, Environmental and Safety Committee includes receiving independent outside assessments of cybersecurity maturity and assessment of plans.

Overall, the Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of NSP-Minnesota. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks. The Board of Directors regularly reviews management’s key risk assessment informed by these processes, and analyzes areas of existing and future risks and opportunities.

Risks Associated with Our Business

Operational Risks

Our natural gas and electric transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.

Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems.

Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and outages which could cause substantial financial losses. These natural gas and electric risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial losses. We maintain insurance against some, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.

Additionally, for natural gas costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant.

The Pipeline Safety Act requires verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of natural gas pipeline infrastructure.

Our utility operations are subject to long-term planning risks.

Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy.

The electric utility sector is undergoing a period of significant change. For example, increases in appliance, lighting and energy efficiency, wider adoption and lower cost of renewable generation and distributed generation, shifts away from coal generation to decrease CO₂ emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if NSP-Minnesota is not able to fully recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution. In addition, we are subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure. This increases the exposure to potential outdating of technologies and resultant risks. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation places downward pressure on sales growth. This may lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets.

We are subject to the risks of nuclear generation.

Our two nuclear stations, PI and Monticello, subject us to the risks of nuclear generation, which include:

• Risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal of radioactive materials;

• Limitations on insurance available to cover losses that might arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor; and,

• Uncertainties with the technological and financial aspects of decommissioning nuclear plants. For example, assumptions regarding decommissioning costs may change based on economic conditions and changes in the expected life of the asset may cause our funding obligations to change.

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The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. The NRC has the authority to impose fines and/or shut down a unit until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the Institute for Nuclear Power Operations reviews our nuclear operations and nuclear generation facilities. Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

If an incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. Furthermore, the non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased regulation of the industry, which may increase our compliance costs.

NSP-Wisconsin’s production and transmission system is operated on an integrated basis with our production and transmission system, and NSP-Wisconsin may be subject to risks associated with our nuclear generation.

We are subject to commodity risks and other risks associated with energy markets and energy production.

If fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows. Low fuel costs have a positive impact on sales, however low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue.

A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Significantly higher energy or fuel costs relative to sales commitments have a negative impact on our cash flows and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and could cause disruptions in our ability to provide electric and/or natural gas services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.

We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Actual settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.

As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures.

If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2018, Xcel Energy Inc. and its utility subsidiaries had approximately $15.8 billion of long-term debt and $1.4 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2018, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $17.8 million and immaterial exposure. Xcel Energy also had additional guarantees of $51.1 million at Dec. 31, 2018 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy Inc. In 2018, 2017 and 2016 we paid $456.3 million, $506.6 million and $395.9 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for NSP-Minnesota is imposed by our state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio. See Note 5 to the consolidated financial statements for further information.

Financial Risks

Our profitability depends on our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.

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The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. In a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that our regulatory commissions will judge all of our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements of utility facilities and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation or tariffs may increase costs of construction and operations. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are recoverable given the existing regulatory mechanisms in place.

Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that our current ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including a disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets.

Also, we may enter into contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global and impacted by issues and events throughout the world. Capital market disruption events and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates.

Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the nuclear decommissioning and/or pension funds, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.

Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and/or breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as Southwest Power Pool, Inc., PJM Interconnection, LLC, MISO and Electric Reliability Council of Texas, in which any credit losses are socialized to all market participants.

We have additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.

Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.

We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future.

Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving NSP-Minnesota could trigger settlement accounting and could require NSP-Minnesota to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid.

Increasing costs associated with health care plans may adversely affect our results of operations.

Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial condition and cash flows. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.

Federal tax law may significantly impact our business.

NSP-Minnesota collects through regulated rates estimated federal, state and local tax payments. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits may change the economics of resources and our resource selections.

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There could be timing delays before regulated rates provide for realization of the tax changes in revenues. In addition, certain IRS tax policies such as the requirement to utilize normalization may impact our ability to economically deliver certain types of resources relative to market prices.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. Growth in customers and sales are correlated with economic conditions.

Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to additional bad debt expense.

Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may impact our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal policy on trade could significantly impact the cost of materials we use. We could be at risk for higher costs for materials and our workforce. There may be delays before these additional costs can be recovered in rates.

Our operations could be impacted by war, acts of terrorism, and threats of terrorism or disruptions due to events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our results of operations, financial condition or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks.

The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation.

Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (e.g., severe storm, severe temperature extremes, wildfires, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.

A cyber incident or security breach could have a material effect on our business.

We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error.

Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which could expose us to liability.

Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business.

Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. In addition, such an event would likely receive federal and state regulatory scrutiny. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and regulatory action could result in a material decrease in revenues and may causesignificant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems or those of our third-party service providers were to fail or be breached, we may be unable to fulfill critical business functions. We are unable to quantify the potential impact of cyber security incidents on our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network monitoring may not be effective given the constant changes to threat vulnerability.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows.

Our operations use third party contractors in addition to employees to perform periodic and on-going work.

We rely on third party contractors to perform work for operations, maintenance and construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance.

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Cyber security breaches have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

Public Policy Risks

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change and new interpretations of existing laws create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system.

We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. All of the steps that NSP-Minnesota has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put NSP-Minnesota in a good position to meet federal or international standards being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.

If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Additionally, the PHMSA, Occupational Safety and Health Administration and other federal agencies have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties. If a serious reliability or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.

Environmental Risks

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.

Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of other parties, caused environmental contamination.

We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows. If our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred to comply with the requirements.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.

Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.

Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require system backup, costs, and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities. While we carry liability insurance, given an extreme event, if NSP-Minnesota was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers and increase the price paid for energy. We may not recover all costs related to mitigating these physical and financial risks.

Climate change may impact a region’s economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

15

Item 1B — Unresolved Staff Comments

None.

Item 2 — Properties

Virtually all of the utility plant property of NSP-Minnesota is subject to the lien of its first mortgage bond indenture.

NSP-Minnesota Station, Location and Unit	Fuel	Installed	MW (a)
Steam:
A.S. King-Bayport, MN, 1 Unit	Coal	1968	511
Sherco-Becker, MN
Unit 1	Coal	1976	680
Unit 2	Coal	1977	682
Unit 3	Coal	1987	517	(b)
Monticello MN, 1 Unit	Nuclear	1971	617
PI-Welch, MN
Unit 1	Nuclear	1973	521
Unit 2	Nuclear	1974	519
Various locations, 4 Units	Wood/Refuse	Various	36	(c)
Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 Units	Natural Gas	1994 - 2005	327
Black Dog-Burnsville, MN, 3 Units	Natural Gas	1987 - 2002	494	(d)
Blue Lake-Shakopee, MN, 6 Units	Natural Gas	1974 - 2005	453
High Bridge-St. Paul, MN, 3 Units	Natural Gas	2008	530
Inver Hills-Inver Grove Heights, MN, 6 Units	Natural Gas	1972	282
Riverside-Minneapolis, MN, 3 Units	Natural Gas	2009	454
Various locations, 14 Units	Natural Gas	Various	67
Wind:
Border-Rolette County, ND, 75 Units	Wind	2015	148	(e)
Courtenay Wind, ND, 100 Units	Wind	2016	195	(e)
Grand Meadow-Mower County, MN, 67 Units	Wind	2008	101	(e)
Nobles-Nobles County, MN, 134 Units	Wind	2010	200	(e)
Pleasant Valley-Mower County, MN, 100 Units	Wind	2015	196	(e)
		Total	7,530

^(a)  Summer 2018 net dependable capacity.

^(b)  Based on NSP-Minnesota’s ownership of 59%.

^(c)  Refuse-derived fuel is made from municipal solid waste.

^(d)  Black Dog Unit 6 was commissioned and placed into operation in the third quarter of 2018.

^(e)  The values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2018:

Conductor Miles
500 KV	2,917
345 KV	13,560
230 KV	2,202
161 KV	615
115 KV	7,372
Less than 115 KV	86,185

NSP-Minnesota had 348 electric utility transmission and distribution substations at Dec. 31, 2018.

Natural gas utility mains at Dec. 31, 2018:

Miles
Transmission	90
Distribution	10,437

Item 3—Legal Proceedings

NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business. Assessment of whether a loss is probable or is a reasonable possibility, and whether a loss or a range of loss is estimable, often involves a series of complex judgments regarding future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) damages sought are indeterminate, (2) proceedings are in the early stages or (3) 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.

See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information.

Item 4—Mine Safety Disclosures

None.

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities

NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. See Note 5 to the consolidated financial statements for further information.

The dividends declared during 2018 and 2017 were as follows:

(Millions of Dollars)	2018		2017
First quarter	$	84.6	$	85.7
Second quarter	88.7		88.0
Third quarter	184.2		243.5
Fourth quarter	82.7		98.7

Item 6 — Selected Financial Data

This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 7 — 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 I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

16

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as, electric margin, 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, for reporting of results, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.

Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and state implementation plan expenses, depreciation and amortization and taxes (other than income taxes).

Earnings Adjusted for Certain Items (Ongoing Earnings)

Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.

Management uses these non-GAAP financial measures to evaluate and provide details of NSP-Minnesota’s core earnings and underlying performance. Management believes these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of NSP-Minnesota.

Results of Operations

NSP-Minnesota’s net income was approximately $492.3 million for 2018, compared with approximately $490.1 million for 2017. The increase in earnings, driven by higher electric margins (before the impact of the TCJA) and natural gas margins, was offset by higher depreciation expense and O&M expenses.

Electric Margin

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

Electric revenues and margin before and after the impact of the TCJA:

(Millions of Dollars)	2018			2017
Electric revenues before TCJA impact	$	4,692.6		$	4,541.7
Electric fuel and purchased power before TCJA impact	(1,706.6		)	(1,626.9		)
Electric margin before TCJA impact	$	2,986.0		$	2,914.8
TCJA impact (offset as a reduction in income tax)	(179.1		)	—
Electric margin	$	2,806.9		$	2,914.8

Electric Margin

(Millions of Dollars)	2018 vs. 2017
Purchased capacity costs	$	31.7
Retail sales growth (including Minnesota decoupling and sales true-up)	23.5
Non-fuel riders	19.0
Estimated impact of weather (net of Minnesota decoupling)	17.4
Wholesale transmission margin	8.0
Interchange agreement billings with NSP-Wisconsin	(17.9		)
Conservation incentive	(8.9		)
Other (net)	(1.6		)
Total increase in electric margin before TCJA impact	$	71.2
TCJA impact (offset as a reduction in income tax)	(179.1		)
Total decrease in electric margin	$	(107.9	)

Natural Gas 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.

Natural gas revenues and margin before and after the impact of the TCJA:

(Millions of Dollars)	2018			2017
Natural gas revenues before TCJA impact	$	590.0		$	531.9
Cost of natural gas sold and transported	(345.1		)	(301.8		)
Natural gas margin before TCJA impact	$	244.9		$	230.1
TCJA impact (offset as a reduction in income tax)	(6.9		)	—
Natural gas margin	$	238.0		$	230.1

Natural Gas Margin

(Millions of Dollars)	2018 vs. 2017
Estimated impact of weather	$	11.8
Sales growth	2.6
Other (net)	0.4
Total increase in natural gas margin before TCJA impact	$	14.8
TCJA impact (offset as a reduction in income tax)	(6.9		)
Total increase in natural gas margin	$	7.9

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased$25.0 million, or 2.1%, for 2018. Significant changes are summarized below:

(Millions of Dollars)	2018 vs. 2017
Business systems and contract labor	$	16.5
Plant generation costs	11.4
Distribution costs	5.4
Nuclear plant operations and amortization	(9.7		)
Other (net)	1.4
Total increase in O&M expenses	$	25.0

17

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

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

• Distribution costs reflect higher maintenance expenses, including vegetation management; and

• Nuclear plant operations and amortization are lower largely reflecting savings initiatives and reduced refueling outage costs.

Conservation Program Expenses — Conservation program expenses decreased$2.1 million, or 1.7%, for 2018. The decrease was due to lower recovery rates, partially offset by additional customer participation in electric conservation programs.

Conservation expenses are generally recovered concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred.

Depreciation and Amortization— Depreciation and amortization expense increased$41.0 million, or 5.9%, for 2018. The increase was primarily driven by capital expenditures due to planned system investments and amortization of certain regulatory assets.

Income Taxes — Income tax expense decreased$172.5 million for 2018 compared with the same period in 2017. The decrease in income tax expense was primarily due to a lower federal tax rate due to the TCJA, lower pretax earnings, a one-time, non-cash, income tax expense related to the impacts of tax reform in 2017, and an increase in plant-related regulatory differences related to ARAM; partially offset by a net tax benefit related to the resolution of appeals/audits in 2017 and a decrease in wind production tax credits.

The ETR was 5.2% for 2018 compared with 29.0% for 2017. The lower ETR in 2018 was primarily due to the adjustments referenced above. The wind PTCs flow back to customers through NSP-Minnesota’s fuel clause and riders.

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 NERC 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.

Tax Reform — Regulatory Proceedings

In December 2017, the TCJA was signed into law, enacting significant changes to the Internal Revenue Code, including a reduction of the corporate income tax rate from 35% to 21% and a resulting reduction in deferred tax assets and liabilities.

As a result of IRS requirements and past regulatory treatment of income taxes in the determination of regulated rates, the impacts of TCJA are primarily recognized as a regulatory liability. Treatment of these tax benefits, (e.g., degree to which benefits will be used to refund currently effective rates and/or used to mitigate other costs and potential future rate increases) is subject to regulatory approval.

Concluded and ongoing regulatory TCJA proceedings:

Utility Service	Approval Date	Additional Information
Electric and Natural Gas	August 2018	Minnesota — In 2018, the MPUC ordered NSP-Minnesota to refund the 2018 impacts of TCJA, including $135 million to electric customers and low income program funding, and $6 million to natural gas customers.
Electric	July 2018	South Dakota — In July 2018, the SDPUC approved a settlement providing a one-time customer refund of $11 million for the 2018 impact of the TCJA, while NSP-Minnesota would retain the TCJA benefits in 2019 and 2020 in exchange for a two-year rate case moratorium.
Natural Gas	November 2018	North Dakota — In November 2018, the NDPSC approved a TCJA settlement in which NSP-Minnesota will amortize $1 million annually of the regulatory asset for the remediation of the MGP site in Fargo, ND and retain the TCJA savings to offset the MGP amortization expense.
Electric	February 2019	North Dakota — In February 2019, the NDPSC approved a settlement including a one-time customer refund of $10 million for 2018, while NSP-Minnesota would retain the TCJA benefits in 2019 and 2020 in exchange for a two-year rate case moratorium.

See Note 7 to the consolidated financial statements for further information.

18

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	Reflects the revenue requirements for 2018 and a true-up for 2017 and is based on a proposed ROE of 10%. MPUC decision is expected during the first quarter of 2019.
CIP Incentive	Electric & Natural Gas	$34	March 2018	Received	MPUC approved 2017 CIP electric and natural gas financial incentives, effective October 2018, of $30 million and $4 million, respectively.
CIP Rider	Electric & Natural Gas	$57	March 2018	Received	The MPUC approved the forecasted 2018 electric and natural gas CIP riders with estimated 2019 recovery of $48 million and $9 million of electric and natural gas CIP expenses, respectively.
2018 GUIC	Natural Gas	$23	November 2017	Pending	Proposed ROE of 10%. MPUC decision is expected during the first quarter of 2019.
2019 GUIC	Natural Gas	$29	November 2018	Pending	Proposed ROE of 10.25%. Timing of MPUC decision is uncertain.
RDF	Electric	$42	October 2018	Received	MPUC approved the 2019 RDF rate based on a net revenue requirement of $42 million, effective January 2019.
RES	Electric	$23	November 2017	Pending	Reflects the revenue requirements for 2018, 2017 true-up and a proposed ROE of 10%. MPUC decision is expected in the first quarter of 2019.

See Rate Matters within Note 10 to the consolidated financial statements for further information.

Mankato Energy Center Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company to purchase the 760 MW natural gas combined cycle Mankato Energy Center for approximately $650 million. NSP-Minnesota previously contracted to purchase the energy and capacity of this facility through a PPA. The asset acquisition is anticipated to close in mid-2019 and is subject to regulatory approvals from the MPUC, NDPSC, FERC, and the DOJ. The acquisition is projected to provide net customer savings of approximately $50 million to $150 million over the life of the plant.

Wind Repowering Acquisition — In December 2018, NSP-Minnesota filed with the MPUC to acquire the Jeffers and Community Wind North wind farms from Longroad Energy. The wind farms will have approximately 70 MW of capacity after being repowered. The repowering is expected to be completed by December 2020 to qualify for the 100% PTC benefit. The acquisition is projected to provide customer savings of approximately $7 million over the life of the wind farms. The cost of the acquisition is $135 million and is pending MPUC approval.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

NSP-Minnesota is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

See Note 8 to the consolidated financial statements for further information.

NSP-Minnesota is exposed to the impact of adverse changes in price for energy and energy related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral.

While NSP-Minnesota expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose NSP-Minnesota to some credit and non-performance risk.

Distress in the financial markets may impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and pension fund and NSP-Minnesota’s ability to earn a return on short-term investments.

Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.

Commodity price risk is also managed through the use of financial derivative instruments. NSP-Minnesota’s risk management policy allows it to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.

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

At Dec. 31, 2018, fair values by source for net commodity trading contract assets were as follows:

	Futures / Forwards
(Millions of Dollars)	Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/ Forwards Fair Value
NSP-Minnesota	2	$	2.2	$	5.4	$	1.7	$	1.4	$	10.7

	Options
(Millions of Dollars)	Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/ Forwards Fair Value
NSP-Minnesota	2	$	0.3	$	4.2	$	0.8	$	—	$	5.3

2 — Prices based on models and other valuation methods.

19

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31, were as follows:

(Millions of Dollars)	2018			2017
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	15.7		$	9.9
Contracts realized or settled during the period	(2.0		)	(3.7		)
Commodity trading contract additions and changes during the period	2.3			9.5
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	16.0		$	15.7

At Dec. 31, 2018, a 10% increase in market prices for commodity trading contracts would increase pretax income by approximately $16.6 million, whereas a 10% decrease would decrease pretax income by approximately $16.5 million. At Dec. 31, 2017, a 10% increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.2 million, whereas a 10% decrease would increase pretax income by approximately $0.2 million.

NSP-Minnesota’s wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations using VaR. VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.

VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period:

(Millions of Dollars)	Year Ended Dec. 31		VaR Limit		Average		High		Low
2018	$	4.83	$	6.00	$	0.62	$	5.63	$	0.06
2017	0.18		3.00		0.21		0.66		0.04

In November 2018, management temporarily increased the VaR limit to accommodate a 10-year transaction. NSP-Minnesota has been systematically hedging the transaction and the consolidated VaR returned below $3 million in January 2019.

Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 24% of its 2019 and approximately 54% of its 2020 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 scheduled to take delivery of approximately 32% of its average enriched nuclear material requirements from these sources. Alternate potential sources provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.

Disruptions in third party nuclear fuel supply contracts due to bankruptcies or change of contract assignments have not materially impacted NSP-Minnesota’s operational or financial performance.

Interest Rate Risk — NSP-Minnesota is subject to interest rate risk. NSP-Minnesota’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

A 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact annual pretax interest expense by approximately $1.5 million in 2018 and $1.1 million in 2017.

NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. The fund is invested in a diversified portfolio of cash equivalents, debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting.

See Note 8 to the consolidated financial statements for further information.

Credit Risk—NSP-Minnesota is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. NSP-Minnesota maintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

At Dec. 31, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.4 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $12.5 million. At Dec. 31, 2017, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $6.9 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $2.6 million.

NSP-Minnesota conducts credit reviews for all counterparties. NSP-Minnesota employ credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase NSP-Minnesota’s credit risk.

Fair Value Measurements

NSP-Minnesota uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value. NSP-Minnesota’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.

See Notes 8 and 9 to the consolidated financial statements for further information.

Commodity Derivatives — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. Given the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2018.

Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2018.

Item 8 — Financial Statements and Supplementary Data

See Item 15-1 for an index of financial statements included herein.

See Note 14 to the consolidated financial statements for further information.

20

Management Report on Internal Controls Over Financial Reporting

The management of NSP-Minnesota is responsible for establishing and maintaining adequate internal control over financial reporting. NSP-Minnesota’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and NSP-Minnesota’s management and board of directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

NSP-Minnesota management assessed the effectiveness of NSP-Minnesota’s internal control over financial reporting as of Dec. 31, 2018. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2018, NSP-Minnesota’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ BEN FOWKE	/s/ ROBERT C. FRENZEL
Ben Fowke	Robert C. Frenzel
Chairman and Chief Executive Officer	Executive Vice President, Chief Financial Officer
Feb. 22, 2019	Feb. 22, 2019

21

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Northern States Power Company, a Minnesota corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Northern States Power Company, a Minnesota corporation and subsidiaries (the "Company") as of December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, cash flows and, common stockholder’s equity for each of the three years in the period ended December 31, 2018, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2019

We have served as the Company’s auditor since 2002.

22

NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (amounts in millions)
	Year Ended Dec. 31
	2018			2017			2016
Operating revenues
Electric, non-affiliates	$	4,034.3		$	4,051.5		$	3,929.1
Electric, affiliates	473.7			490.2			475.5
Natural gas	583.1			531.9			467.4
Other	30.8			28.4			28.3
Total operating revenues	5,121.9			5,102.0			4,900.3
Operating expenses
Electric fuel and purchased power	1,701.1			1,626.9			1,542.6
Cost of natural gas sold and transported	345.1			301.8			252.8
Cost of sales — other	19.7			18.1			20.0
Operating and maintenance expenses	1,223.3			1,198.3			1,232.2
Conservation program expenses	118.0			120.1			97.9
Depreciation and amortization	741.6			700.6			596.7
Taxes (other than income taxes)	256.6			253.5			246.0
Total operating expenses	4,405.4			4,219.3			3,988.2
Operating income	716.5			882.7			912.1
Other expense, net	(6.5		)	(9.1		)	(12.6		)
Allowance for funds used during construction — equity	23.8			29.5			27.7
Interest charges and financing costs
Interest charges — includes other financing costs of $7.4, $7.3 and $7.1 respectively	226.8			228.4			226.5
Allowance for funds used during construction — debt	(12.5		)	(15.1		)	(12.5		)
Total interest charges and financing costs	214.3			213.3			214.0
Income before income taxes	519.5			689.8			713.2
Income taxes	27.2			199.7			224.5
Net income	$	492.3		$	490.1		$	488.7
See Notes to Consolidated Financial Statements

23

NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (amounts in millions)
	Year Ended Dec. 31
	2018			2017			2016
Net income	$	492.3		$	490.1		$	488.7
Other comprehensive income (loss)
Pension and retiree medical benefits:
Net pension and retiree medical benefits gains (losses) arising during the period, net of tax of $0.3, $(0.4) and $(0.5), respectively	0.6			(0.5		)	(0.7		)
Amortization of losses included in net periodic benefit cost, net of tax of $0.1, $0.1 and $0, respectively	0.2			0.1			0.1
	0.8			(0.4		)	(0.6		)
Derivative instruments:
Net fair value increase, net of tax of $0, $0 and $0, respectively	—			0.1			—
Reclassification of losses to net income, net of tax of $0.3, $0.6 and $0.6, respectively	0.7			0.9			0.9
	0.7			1.0			0.9
Marketable securities:
Net fair value decrease, net of tax of $0, $0 and $0, respectively	(0.1		)	—			—
Other comprehensive income	1.4			0.6			0.3
Comprehensive income	$	493.7		$	490.7		$	489.0
See Notes to Consolidated Financial Statements

24

NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (amounts in millions)
	Year Ended Dec. 31
	2018			2017			2016
Operating activities
Net income	$	492.3		$	490.1		$	488.7
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	748.1			707.0			602.9
Nuclear fuel amortization	121.9			114.4			117.0
Deferred income taxes	41.3			193.2			196.2
Allowance for equity funds used during construction	(23.8		)	(29.5		)	(27.7		)
Provision for bad debts	16.2			15.7			15.0
Net realized and unrealized hedging and derivative transactions	27.0			(2.8		)	3.7
Changes in operating assets and liabilities:
Accounts receivable	(42.7		)	(29.8		)	(53.1		)
Accrued unbilled revenues	7.4			(18.1		)	(32.5		)
Inventories	(21.4		)	7.6			(1.1		)
Other current assets	94.4			(25.3		)	(17.0		)
Accounts payable	10.5			46.5			24.1
Net regulatory assets and liabilities	182.3			(36.4		)	46.9
Other current liabilities	(64.0		)	(71.8		)	19.1
Pension and other employee benefit obligations	(75.8		)	(56.7		)	(42.3		)
Other, net	(31.5		)	(31.3		)	(35.0		)
Net cash provided by operating activities	1,482.2			1,272.8			1,304.9
Investing activities
Utility capital/construction expenditures	(1,149.7		)	(987.2		)	(1,176.8		)
Purchases of investment securities	(852.9		)	(1,690.5		)	(506.3		)
Proceeds from the sale of investment securities	832.6			1,668.9			478.9
Investments in utility money pool arrangement	(805.0		)	(122.0		)	(747.5		)
Repayments from utility money pool arrangement	805.0			122.0			747.5
Other, net	(3.5		)	(3.5		)	(1.0		)
Net cash used in investing activities	(1,173.5		)	(1,012.3		)	(1,205.2		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	130.0			(65.0		)	(138.0		)
Borrowings under utility money pool arrangement	479.0			838.0			424.0
Repayments under utility money pool arrangement	(564.0		)	(753.0		)	(424.0		)
Proceeds from issuance of long-term debt	—			585.2			342.5
Repayments of long-term debt, including reacquisition premiums	—			(507.9		)	—
Capital contributions from parent	108.8			145.0			96.7
Dividends paid to parent	(456.3		)	(506.6		)	(395.9		)
Net cash used in by financing activities	(302.5		)	(264.3		)	(94.7		)
Net change in cash and cash equivalents	6.2			(3.8		)	5.0
Cash and cash equivalents at beginning of period	43.8			47.6			42.6
Cash and cash equivalents at end of period	$	50.0		$	43.8		$	47.6
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(207.4	)	$	(214.2	)	$	(201.4	)
Cash received (paid) for income taxes, net	89.0			(70.9		)	(39.0		)
Supplemental disclosure of non-cash investing transactions:
Accrued property, plant and equipment additions	$	92.5		$	93.1		$	120.8
Inventory transfers to property, plant and equipment	60.8			17.3			35.1
Allowances for equity funds used during construction	23.8			29.5			27.7
See Notes to Consolidated Financial Statements

25

NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (amounts in millions, except share and per share data)
	Dec. 31
	2018			2017
Assets
Current assets
Cash and cash equivalents	$	50.0		$	43.8
Accounts receivable, net	380.9			345.1
Accounts receivable from affiliates	11.0			48.5
Accrued unbilled revenues	270.3			277.7
Inventories	299.4			337.7
Regulatory assets	280.3			276.4
Derivative instruments	25.8			25.2
Prepaid taxes	—			79.1
Prepayments and other	28.9			43.7
Total current assets	1,346.6			1,477.2
Property, plant and equipment	13,541.7			13,033.6
Other assets
Nuclear decommissioning fund and other investments	2,107.2			2,192.4
Regulatory assets	1,454.1			1,190.4
Derivative instruments	17.0			28.1
Other	3.3			4.1
Total other assets	3,581.6			3,415.0
Total assets	$	18,469.9		$	17,925.8
Liabilities and Equity
Current liabilities
Short-term debt	$	150.0		$	20.0
Borrowings under utility money pool arrangement	—			85.0
Accounts payable	393.6			368.3
Accounts payable to affiliates	109.7			80.1
Regulatory liabilities	262.4			83.4
Taxes accrued	230.1			229.3
Accrued interest	67.2			65.9
Dividends payable to parent	82.7			98.7
Derivative instruments	16.5			17.7
Customer deposits	53.7			95.4
Other	154.8			153.0
Total current liabilities	1,520.7			1,296.8
Deferred credits and other liabilities
Deferred income taxes	1,682.4			1,612.3
Deferred investment tax credits	21.1			22.5
Regulatory liabilities	1,984.7			1,978.5
Asset retirement obligations	2,177.9			2,083.9
Derivative instruments	112.2			102.7
Pension and employee benefit obligations	305.1			331.1
Other	155.5			89.4
Total deferred credits and other liabilities	6,438.9			6,220.4
Commitments and contingencies
Capitalization
Long-term debt	4,937.2			4,933.0
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2018 and 2017, respectively	—			—
Additional paid in capital	3,624.2			3,580.2
Retained earnings	1,972.0			1,919.9
Accumulated other comprehensive loss	(23.1		)	(24.5		)
Total common stockholder’s equity	5,573.1			5,475.6
Total liabilities and equity	$	18,469.9		$	17,925.8
See Notes to Consolidated Financial Statements

26

NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY (amounts in millions, except share data)
	Common Stock								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2015	1,000,000	$	—	$	3,323.8	$	1,864.3		$	(21.1	)	$	5,167.0
Net income						488.7						488.7
Other comprehensive income									0.3			0.3
Dividends declared on common stock						(411.7		)				(411.7		)
Contribution of capital by parent				111.3								111.3
Balance at Dec. 31, 2016	1,000,000	$	—	$	3,435.1	$	1,941.3		$	(20.8	)	$	5,355.6
Net income						490.1						490.1
Other comprehensive income									0.6			0.6
Dividends declared on common stock						(515.8		)				(515.8		)
Contribution of capital by parent				145.1								145.1
Adoption of ASU No. 2018-02						4.3			(4.3		)	—
Balance at Dec. 31, 2017	1,000,000	$	—	$	3,580.2	$	1,919.9		$	(24.5	)	$	5,475.6
Net income						492.3						492.3
Other comprehensive income									1.4			1.4
Dividends declared on common stock						(440.2		)				(440.2		)
Contribution of capital by parent				44.0								44.0
Balance at Dec. 31, 2018	1,000,000	$	—	$	3,624.2	$	1,972.0		$	(23.1	)	$	5,573.1
See Notes to Consolidated Financial Statements

27

Notes to Consolidated Financial Statements

1.    Summary of Significant Accounting Policies

General — NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.

NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.

NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 3 for further information.

NSP-Minnesota’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions.

NSP-Minnesota has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates — NSP-Minnesota uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting — NSP-Minnesota accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

• Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — NSP-Minnesota accounts for income taxes using the asset and liability method, which requires deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. NSP-Minnesota uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset.

Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. NSP-Minnesota recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.

Recognition of changes in uncertain tax positions are reflected as a component of income tax.

NSP-Minnesota reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including NSP-Minnesota, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 7 for further information.

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred.

28

Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made.

For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

NSP-Minnesota records depreciation expense using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.6% for 2018, 3.6% for 2017, and 3.2% for 2016.

See Note 3 for further information.

AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset.

Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Minnesota also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

See Note 10 for further information.

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval.

For ratemaking purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each facility’s expected service life based on the triennial decommissioning studies filed with state commissions. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.

Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.

See Notes 8 and 10 for further information.

Benefit Plans and Other Postretirement Benefits — NSP-Minnesota maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

Revenue From Contracts With Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.

NSP-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees.

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

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

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

See Note 6 for further information.

29

Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of 3 months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

As of Dec. 31, 2018 and 2017, the allowance for bad debts was $23.5 million and $21.3 million, respectively.

Inventory— Inventory is recorded at average cost. As of Dec. 31, 2018, materials and supplies, fuel and natural gas inventory were $176.3 million, $88.5 million, and $34.6 million, respectively. As of Dec. 31, 2017, materials and supplies, fuel and natural gas inventory were $209.2 million, $94.5 million, and $34.0 million, respectively.

Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs.

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, NSP-Minnesota may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.

See Notes 8 and 9 for further information.

Derivative Instruments— NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.

Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.

Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

See Note 8 for further information.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 8 for further information.

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility rates.

Alternative Revenue — Certain rate rider mechanisms (including decoupling and CIP programs) qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, such as collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items.

Billing amounts are revised periodically for differences between the total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers in the period earned.

See Note 6 for further information.

Conservation Programs — Costs incurred for CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from when they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Emission Allowances — Emission allowances are recorded at cost plus broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

Nuclear Refueling Outage Costs —NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes refueling outage costs over the period between refueling outages consistent with rate recovery.

RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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2. Accounting Pronouncements

Recently Issued

Leases — In 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which requires balance sheet recognition of right-of-useassets and lease liabilities for most leases. Adoptionwill occur on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions of whether agreements existing before the adoption date contain leases, and whether existing leases are operating or capital/finance leases.

NSP-Minnesota expects to utilize other expedients offered by the new standard and Leases, Topic 842 (ASU No. 2018-11), including elections to not recognize short term leases on the consolidated balance sheet for certain classes of assets and to implement the standard on a prospective basis. NSP-Minnesota’s implementation of the new guidance is substantially complete, and is expected to result in the recognition of right-of-use assets and lease liabilities in the first quarter of 2019 for operating leases for the use of real estate, equipment and certain natural gas generating facilities operated under PPAs.

The implementation isnot expected to have a significant impact on NSP-Minnesota’s consolidatedfinancial statements, other than first-time recognition of these operating leases on the consolidated balance sheet.

Recently Adopted

Revenue Recognition— In 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. NSP-Minnesota implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance.

The implementation did not have a material impact on NSP-Minnesota’s consolidated financial statements, other than increased disclosures regarding revenues related to contracts with customers.

Classification and Measurement of Financial Instruments — In 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes.

NSP-Minnesota implemented the guidance on Jan. 1, 2018 and the adoption impacts were not material.

Presentation of Net Periodic Benefit Cost — In 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 portion of pension cost may be presented as a component of operating income. In addition, only the service cost portion of pension cost is eligible for capitalization.

As a result of regulatory accounting treatment, a similar amount of pension cost, including non-service components, will be recognized consistent with historical ratemaking and the impacts of adoption are limited to changes in classification of non-service costs in the consolidated statement of income.

NSP-Minnesota implemented the new guidance on Jan. 1, 2018. As a result, $14.8 million and $13.6 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other expense, net on the consolidated income statement for 2017 and 2016, respectively. NSP-Minnesota used benefit cost amounts disclosed for prior periods as the basis for retrospective application.

3. Property, Plant and Equipment

Major classes of property, plant and equipment:

(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
Property, plant and equipment
Electric plant	$	17,749.3		$	17,024.9
Natural gas plant	1,475.5			1,370.3
Common and other property	803.1			724.1
CWIP	615.1			530.1
Total property, plant and equipment	20,643.0			19,649.4
Less accumulated depreciation	(7,454.8		)	(7,018.2		)
Nuclear fuel	2,770.4			2,697.4
Less accumulated amortization	(2,416.9		)	(2,295.0		)
	$	13,541.7		$	13,033.6

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2018:

(Millions of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Percent Owned
Electric Generation:
Sherco Unit 3	$	604.2	$	415.0	$	1.0	59	%
Sherco Common Facilities	145.4		100.2		1.2		80
Other	4.8		3.4		—		59
Electric Transmission:
CapX2020 Transmission	959.6		72.7		1.9		51
Other	10.6		2.3		—		50
Total	$	1,724.6	$	593.6	$	4.1

NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

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4.    Regulatory Assets and Liabilities

Regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.

Components of regulatory assets:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	28.1	$	424.3	$	28.5	$	403.7
Net AROs (a)	1, 10	Plant lives	—		323.4		—		193.1
Excess deferred taxes - TCJA	7	Various	—		153.3		—		133.1
Recoverable deferred taxes on AFUDC recorded in plant		Plant lives	—		117.6		—		119.0
Benson biomass PPA termination and asset purchase		Ten years	9.8		85.8		—		—
Contract valuation adjustments (b)	1, 8	Term of related contract	14.1		76.0		14.4		89.8
Laurentian biomass PPA termination		Five years	18.1		73.3		—		—
PI extended power update		Sixteen years	3.1		55.8		3.3		58.4
Purchased power contracts costs		Term of related contract	2.8		36.6		1.8		39.3
Conservation programs (c)	1	One to two years	34.5		21.1		40.4		25.9
Losses on reacquired debt		Term of related debt	2.1		15.5		2.2		17.6
Environmental remediation costs	1, 10	Pending future rate cases	1.3		14.3		—		24.6
Nuclear refueling outage costs	1	One to two years	36.3		13.5		49.3		19.7
Deferred purchased natural gas and electric energy costs		One to three years	5.6		12.6		13.5		13.3
Sales true-up and revenue decoupling		One to two years	38.3		6.7		37.3		12.4
State commission adjustments		Plant lives	—		3.4		—		3.5
Renewable resources and environmental initiatives		One to two years	39.2		0.4		45.9		0.4
Gas pipeline inspection and remediation costs		Less than one year	27.4		—		22.6		4.5
Other		Various	19.6		20.5		17.2		32.1
Total regulatory assets			$	280.3	$	1,454.1	$	276.4	$	1,190.4

^(a)  Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

^(b)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(c)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	153.7	$	1,465.1	$	—	$	1,516.1
Plant removal costs	1, 10	Plant lives	—		484.6		—		441.6
ITC deferrals (b)	1	Various	—		8.9		—		9.5
Deferred electric energy costs		Less than one year	22.8		—		11.3		—
DOE Settlement		Less than one year	13.0		—		12.8		—
Contract valuation adjustments (c)	1, 8	Less than one year	10.4		—		17.2		—
Renewable resources and environmental initiatives		Less than one year	8.8		—		19.4		—
Other		Various	53.7		26.1		22.7		11.3
Total regulatory liabilities (d)			$	262.4	$	1,984.7	$	83.4	$	1,978.5

^(a)  Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

^(b)  Includes impact of lower federal tax rate due to the TCJA.

^(c)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(d)  Revenue subject for refund of $12.5 million and $15.1 million for 2018 and 2017, respectively, is included in other current liabilities.

At Dec. 31, 2018 and 2017, approximately $149 million and $142 million, respectively, of NSP-Minnesota’s regulatory assets represented past expenditures not earning a return. Amounts primarily related to purchased natural gas and electric energy costs and certain expenditures associated with pension.

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5.    Borrowings and Other Financing Instruments

Short-Term Borrowings

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

	Three Months Ended Dec. 31, 2018			Year Ended
(Amounts in Millions, Except Interest Rates)				2018			2017			2016
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	—			—			85			—
Average amount outstanding	18			17			25			16
Maximum amount outstanding	76			143			142			225
Weighted average interest rate, computed on a daily basis	2.23		%	1.96		%	1.14		%	0.69		%
Weighted average interest rate at period end	N/A			N/A			1.18			N/A

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

Commercial paper outstanding for NSP-Minnesota was as follows:

	Three Months Ended Dec. 31, 2018			Year Ended Dec. 31
(Amounts in Millions, Except Interest Rates)				2018			2017			2016
Borrowing limit	$	500		$	500		$	500		$	500
Amount outstanding at period end	150			150			20			85
Average amount outstanding	62			38			62			73
Maximum amount outstanding	198			198			237			353
Weighted average interest rate, computed on a daily basis	2.53		%	2.08		%	1.10		%	0.65		%
Weighted average interest rate at end of period	2.97			2.97			1.93			0.94

Letters of Credit — NSP-Minnesota uses letters of credit, typically with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2018 and 2017, there were $37 million and $24 million of letters of credit outstanding, respectively, under the credit facility. Amounts approximate their fair value.

Credit Facility — 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.

Features of NSP-Minnesota’s credit facility:

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions)		Additional Periods For Which a One-Year Extension May Be Requested (b)
2018		2017
48	%	48	%	$	100	2

^(a)  The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

^(b)  All extension requests are subject to majority bank group approval.

The credit facility has a cross-default provision that NSP-Minnesota will be in default on its borrowings under the facility if it or any of its subsidiaries whose total assets exceed 15% of NSP-Minnesota’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.

If NSP-Minnesota does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2018, NSP-Minnesota was in compliance with all financial covenants on its debt agreements.

NSP-Minnesota had the following committed credit facilities available as of Dec. 31, 2018 (in millions):

Credit Facility (a)		Drawn(b)		Available
$	500	$	187	$	313

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

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

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

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Long-Term Borrowings and Other Financing Instruments

Generally, all property of NSP-Minnesota is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

Long term debt obligations for NSP-Minnesota as of Dec. 31:

(Millions of Dollars)	Maturity Range	Interest Rate Range 2018	Interest Rate Range 2017	2018			2017
NSP-Minnesota
Mortgage bonds	2020-2047	2.15% - 7.13%	2.15% - 7.13%	$	5,000		$	5,000
Unamortized discount				(21		)	(22		)
Unamortized debt issuance cost				(42		)	(45		)
Current maturities				—			—
Total				$	4,937		$	4,933

Maturities of long-term debt are as follows:

(Millions of Dollars)
2019	$	—
2020	300
2021	—
2022	300
2023	400

During 2018, NSP-Minnesota did not complete any new financings.

2017 financings:

	Amount	Financing Instrument	Interest Rate		Maturity Date
NSP-Minnesota	600 million	First mortgage bonds	3.60	%	Sept. 15, 2047

Deferred Financing Costs— Deferred financing costs of approximately $42 million and $45 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2018 and 2017, respectively.

Dividend Restrictions — NSP-Minnesota’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividend payments are solely to be paid from retained earnings.

NSP-Minnesota’s state regulatory commission imposes the most restrictive dividend limitations.

Requirements and actuals as of Dec. 31, 2018:

	Equity to Total Capitalization Ratio - Required Range				Equity to Total Capitalization Ratio - Actual
	Low		High		2018
NSP-Minnesota	47.1	%	57.5	%	52.3	%

	Unrestricted Retained Earnings			Total Capitalization			Limit on Total Capitalization
NSP-Minnesota	$	1.0	billion	$	10.7	billion	$	11.5	billion

6. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following:

	Year Ended Dec. 31, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,308.4	$	308.8	$	27.2	$	1,644.4
C&I	2,052.1		239.3		0.2		2,291.6
Other	36.5		—		3.4		39.9
Total retail	3,397.0		548.1		30.8		3,975.9
Wholesale	189.2		—		—		189.2
Transmission	238.1		—		—		238.1
Interchange	473.7		—		—		473.7
Other	28.3		11.7		—		40.0
Total revenue from contracts with customers	4,326.3		559.8		30.8		4,916.9
Alternative revenue and other	181.7		23.3		—		205.0
Total revenues	$	4,508.0	$	583.1	$	30.8	$	5,121.9

7.    Income Taxes

Federal Tax Reform— In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes NSP-Minnesota), generally beginning in 2018, include:

• Corporate federal tax rate reduction from 35% to 21%;

• Normalization of resulting plant-related excess deferred taxes;

• Elimination of the corporate alternative minimum tax;

• Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;

• Limitations on certain executive compensation deductions;

• Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80% of taxable income);

• Repeal of the section 199 manufacturing deduction; and,

• Reduced deductions for meals and entertainment as well as state and local lobbying.

Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements.

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Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment.

Estimated impacts of the new tax law for NSP-Minnesota in December 2017 included:

• $1.1 billion ($1.5 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property;

• $133 million and $56 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and

• $19 million of total estimated income tax expense related to the federal tax reform implementation, and a $5 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.

Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.

Federal Tax Loss Carryback Claims — In 2012 - 2015, Xcel Energy 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, Xcel Energy recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012.

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

Tax Year(s)	Expiration
2009 - 2014	October 2019
2015	September 2019
2016	September 2020
2017	September 2021

In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. In 2017, Xcel Energy and the Office of Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2018, 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 the fourth quarter of 2018, the IRS began an audit of tax years 2014 - 2016, however 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 Dec. 31, 2018, NSP-Minnesota’s earliest open tax year subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the fourth quarter of 2018, the Minnesota audit of tax years 2010 - 2014 concluded with no material adjustments.

Unrecognized Tax 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)	Dec. 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	11.6	$	10.2
Unrecognized tax benefit — Temporary tax positions	5.3		7.9
Total unrecognized tax benefit	$	16.9	$	18.1

Changes in unrecognized tax benefits:

(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	18.1		$	60.8		$	55.4
Additions based on tax positions related to the current year	2.0			2.7			3.7
Reductions based on tax positions related to the current year	(0.3		)	(1.7		)	(0.2		)
Additions for tax positions of prior years	0.6			5.7			3.9
Reductions for tax positions of prior years	(1.1		)	(49.4		)	(2.0		)
Settlements with taxing authorities	(2.4		)	—			—
Balance at Dec. 31	$	16.9		$	18.1		$	60.8

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

(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(12.7	)	$	(12.8	)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $7.3 million and $5.7 million at Dec. 31, 2018 and Dec. 31, 2017, respectively.

As the IRS Appeals and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $13.7 million in the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)	2018			2017			2016
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.9	)	$	(2.0	)	$	(0.2	)
Interest (expense) income related to unrecognized tax benefits	(0.3		)	1.1			(1.8		)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(1.2	)	$	(0.9	)	$	(2.0	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2018, 2017, or 2016.

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Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2018			2017
Federal NOL carryforward	$	—		$	631.6
Federal tax credit carryforwards	379.4			301.6
State NOL carryforwards	221.2			275.5
Valuation allowances for state NOL carryforwards	(0.8		)	(0.9		)
State tax credit carryforwards, net of federal detriment (a)	87.9			90.7
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(78.5		)	(82.2		)

^(a)  State tax credit carryforwards are net of federal detriment of $23.4 million and $24.1 million as of Dec. 31, 2018 and 2017, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $20.9 million and $21.8 million as of Dec. 31, 2018 and 2017, respectively.

Federal carryforward periods expire between 2021 and 2038 and state carryforward periods expire between 2019 and 2035.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:

	2018		2017 (a)		2016 (a)
Federal statutory rate	21.0	%	35.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	7.1		5.8		5.8
Increases (decreases) in tax from:
Wind PTCs recognized	(13.6	)	(11.4	)	(8.2	)
Regulatory differences - ARAM (b)	(9.1	)	(0.1	)	(0.1	)
Other tax credit recognized, net of federal income tax expense	(1.3	)	(1.0	)	(0.8	)
Regulatory differences - other utility plant items	0.3		(0.2	)	(0.2	)
Change in unrecognized tax benefits	0.1		(1.6	)	0.2
Tax reform	—		2.7		—
Other, net	0.7		(0.2	)	(0.2	)
Effective income tax rate	5.2	%	29.0	%	31.5	%

^(a)  Prior periods have been reclassified to conform to current year presentation.

^(b)  ARAM is a method to flow back excess deferred taxes to customers.

Components of income tax expense for years ended Dec. 31:

(Millions of Dollars)	2018			2017			2016
Current federal tax (benefit) expense	$	(16.8	)	$	29.6		$	19.3
Current state tax expense	5.2			14.7			9.4
Current change in unrecognized tax (benefit) expense	(1.1		)	(36.2		)	1.3
Deferred federal tax (benefit) expense	(2.4		)	121.6			142.3
Deferred state tax expense	42.1			46.7			53.8
Deferred change in unrecognized tax expense	1.6			24.9			0.1
Deferred ITCs	(1.4		)	(1.6		)	(1.7		)
Total income tax expense	$	27.2		$	199.7		$	224.5

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)	2018			2017			2016
Deferred tax expense (benefit) excluding items below	$	70.1		$	(1,176.4	)	$	225.1
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(28.2		)	1,369.9			(28.7		)
Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other	(0.6		)	(0.3		)	(0.2		)
Deferred tax expense	$	41.3		$	193.2		$	196.2

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2018			2017
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,257.6		$	2,253.2
Regulatory assets	263.1			222.7
Pension expense	64.7			54.2
Other	11.3			16.4
Total deferred tax liabilities	$	2,596.7		$	2,546.5
Deferred tax assets:
Regulatory liabilities	$	382.8		$	386.6
Tax credit carryforward	467.3			392.4
NOL carryforward	17.9			153.5
NOL and tax credit valuation allowance	(78.6		)	(82.2		)
Other employee benefits	38.6			37.3
Deferred ITCs	6.4			6.8
Rate refund	49.7			6.6
Other	30.2			33.2
Total deferred tax assets	$	914.3		$	934.2
Net deferred tax liability	$	1,682.4		$	1,612.3

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

• 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.

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Specific valuation methods include:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted 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. The investments in commingled funds may be redeemed for NAV with proper 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, however, may be delayed or discounted as a result of fund illiquidity.

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

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

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations 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 forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as 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.

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

Non-Derivative Fair Value Measurements

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other 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 over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.

Unrealized gains for the nuclear decommissioning fund were $450.1 million and $559.9 million as of Dec. 31, 2018 and 2017, respectively, and unrealized losses were $44.8 million and $7.4 million as of Dec. 31, 2018 and 2017, respectively.

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

	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 $52.5 million of rabbi trust assets and miscellaneous investments.

	Dec. 31, 2017
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	28.7	$	28.7	$	—	$	—	$	—	$	28.7
Commingled funds	701.3		222.8		—		—		659.1		$	881.9
Debt securities	437.7		—		441.6		—		—		$	441.6
Equity securities	423.1		791.1		—		—		—		$	791.1
Total	$	1,590.8	$	1,042.6	$	441.6	$	—	$	659.1	$	2,143.3

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $49.1 million of rabbi trust assets and miscellaneous investments.

For the years ended Dec. 31, 2018 and 2017, there were no Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

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Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2018:

	Final Contractual Maturity
(Millions of Dollars)	Due in 1Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	10.6	$	106.9	$	210.5	$	107.6	$	435.6

Rabbi Trusts

NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions.

Cost and fair value of assets held in rabbi trusts:

	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, 2017
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	0.8	$	0.8	$	—	$	—	$	0.8
Mutual funds	10.3		11.3		—		—		$	11.3
Total	$	11.1	$	12.1	$	—	$	—	$	12.1

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

Derivative 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.

As of Dec. 31, 2018, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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

As of Dec. 31, 2018, NSP-Minnesota had no vehicle fuel contracts designated as cash flow hedges. NSP-Minnesota 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 in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Immaterial amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2018 and 2017.

As of Dec. 31, 2018, there were no net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.

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

Gross notional amounts of commodity forwards, options and FTRs at Dec. 31:

(Amounts in Millions)(a) (b)	2018	2017
MWh of electricity	56.8	41.7
MMBtu of natural gas	42.7	23.8
Gallons of vehicle fuel	—	0.2

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

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. As of Dec. 31, 2018, six of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $35.9 million or 44% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.

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Two of the 10 most significant counterparties, comprising $14.4 million or 18% 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. One of the 10 most significant counterparties, comprising $1.3 million or 2% of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. One of the 10 most significant counterparties, comprising $11.8 million or 14% of this credit exposure, had credit quality less than investment grade based on rating from internal analysis. Seven of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)	2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(20.9	)	$	(18.2	)	$	(19.1	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			0.1			—
After-tax net realized losses on derivative transactions reclassified into earnings	0.7			0.9			0.9
Adoption of ASU. 2018-02 (a)	—			(3.7		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(20.2	)	$	(20.9	)	$	(18.2	)

^(a)  In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

Impact of derivative activity:

	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2018
Other derivative instruments
Electric commodity	$	—	$	(5.5	)
Natural gas commodity	—		1.8
Total	$	—	$	(3.7	)
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Vehicle fuel and other commodity	$	0.1	$	—
Total	$	0.1	$	—
Other derivative instruments
Electric commodity	$	—	$	9.3
Natural gas commodity	—		(1.9		)
Total	$	—	$	7.4
Year Ended Dec. 31, 2016
Other derivative instruments
Electric commodity	—		14.4
Natural gas commodity	—		(1.2		)
Total	$	—	$	13.2

	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)
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1.1		(a)	$	—			$	—
Vehicle fuel and other commodity	(0.1		)	(b)	—				—
Total	$	1.0			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	10.9		(c)
Electric commodity	—				3.3			(d)	—
Natural gas commodity	—				(1.9		)	(e)	(1.3		)	(e)
Total	$	—			$	1.4			$	9.6
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Interest rate	$	1.5		(a)	$	—			$	—
Total	$	1.5			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	9.4		(c)
Electric commodity	—				(13.8		)	(d)	—
Natural gas commodity	—				1.0			(e)	(1.2		)	(e)
Total	$	—			$	(12.8	)		$	8.2
Year Ended Dec. 31, 2016
Derivatives designated as cash flow hedges
Interest rate	$	1.4		(a)	$	—			$	—
Vehicle fuel and other commodity	0.1			(b)	—				—
Total	$	1.5			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	2.8		(c)
Electric commodity	—				(6.1		)	(d)	—
Natural gas commodity	—				4.0			(e)	(2.2		)	(e)
Total	$	—			$	(2.1	)		$	0.6

^(a)  Amounts are recorded to interest charges.

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

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

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

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

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2018, 2017 and 2016.

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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 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 if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2018 and 2017, there were no derivative instruments in a liability position with such underlying contract provisions.

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

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2018 and 2017:

	Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total		Netting (a)					Fair Value						Fair Value Total		Netting (a)
(Millions of Dollars)	Level 1		Level 2		Level 3							Total		Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	—	$	—	$	—	$	—		$	—	$	—	$	0.1	$	—	$	0.1	$	—		$	0.1
Other derivative instruments:
Commodity trading	1.1		27.1		2.2		30.4		(16.0		)	14.4		1.7		17.1		0.1		18.9		(11.7		)	7.2
Electric commodity	—		—		10.5		10.5		(0.1		)	10.4		—		—		17.6		17.6		(0.4		)	17.2
Natural gas commodity	—		1.0		—		1.0		—			1.0		—		0.1		—		0.1		—			0.1
Total current derivative assets	$	1.1	$	28.1	$	12.7	$	41.9	$	(16.1	)	25.8		$	1.7	$	17.3	$	17.7	$	36.7	$	(12.1	)	24.6
PPAs (b)												—													0.6
Current derivative instruments												$	25.8												$	25.2
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	25.3	$	5.0	$	30.3	$	(13.4	)	$	16.9	$	—	$	29.1	$	5.4	$	34.5	$	(6.5	)	$	28.0
Total noncurrent derivative assets	$	—	$	25.3	$	5.0	$	30.3	$	(13.4	)	16.9		$	—	$	29.1	$	5.4	$	34.5	$	(6.5	)	28.0
PPAs (b)												0.1													0.1
Noncurrent derivative instruments												$	17.0												$	28.1

	Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total		Netting (a)					Fair Value						Fair Value Total		Netting (a)
(Millions of Dollars)	Level 1		Level 2		Level 3							Total		Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1.4	$	23.9	$	1.7	$	27.0	$	(24.5	)	$	2.5	$	1.7	$	13.9	$	—	$	15.6	$	(12.0	)	$	3.6
Electric commodity	—		—		0.1		0.1		(0.1		)	—		—		—		0.4		0.4		(0.4		)	—
Total current derivative liabilities	$	1.4	$	23.9	$	1.8	$	27.1	$	(24.6	)	2.5		$	1.7	$	13.9	$	0.4	$	16.0	$	(12.4	)	3.6
PPAs (b)												14.0													14.1
Current derivative instruments												$	16.5												$	17.7
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	0.1	$	16.0	$	1.6	$	17.7	$	17.9		$	35.6	$	—	$	22.2	$	—	$	22.2	$	(9.4	)	$	12.8
Total noncurrent derivative liabilities	$	0.1	$	16.0	$	1.6	$	17.7	$	17.9		35.6		$	—	$	22.2	$	—	$	22.2	$	(9.4	)	12.8
PPAs (b)												76.6													89.9
Noncurrent derivative instruments												$	112.2												$	102.7

^(a)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2018 and 2017. At Dec. 31, 2018 and 2017, derivative assets and liabilities include $31.5 million and $0 million of obligations to return cash collateral, respectively. At Dec. 31, 2018 and 2017, derivative assets and liabilities include the rights to reclaim cash collateral of $8.7 million and $3.1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  During 2006, 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.

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Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2018, 2017 and 2016:

	Year Ended Dec. 31
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	22.6		$	15.3		$	13.0
Purchases	26.4			40.6			28.0
Settlements	(17.2		)	(41.7		)	(47.2		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(1.5		)	5.5			—
Net (losses) gains recognized as regulatory assets and liabilities	(16.0		)	2.9			21.5
Balance at Dec. 31	$	14.3		$	22.6		$	15.3

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

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended 2016 - 2018.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

	2018				2017
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,937.2	$	5,230.9	$	4,933.0	$	5,601.9

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

9.Benefit Plans and Other Postretirement Benefits

Xcel Energy, which includes NSP-Minnesota, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service and average pay. Xcel Energy’s and NSP-Minnesota’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2018 and 2017 were $33 million and $37 million, respectively, of which $4 million and $5 million were attributable to NSP-Minnesota. In 2018 and 2017, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million and $5 million, respectively, of which $1 million was attributable to NSP-Minnesota in both years.

In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to NSP-Minnesota will be supplemented by NSP-Minnesota’s consolidated operating cash flows.

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees.

• NSP-Minnesota discontinued subsidizing health care benefits for non-bargaining employees retiring after 1998 and for bargaining employees who retired after 1999.

Xcel Energy and NSP-Minnesota base the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios.

For pension assets, Xcel Energy and NSP-Minnesota consider the historical returns achieved by their asset portfolio over the past 20 years or longer period, as well as the long-term projected return levels. Xcel Energy and NSP-Minnesota continually review their pension assumptions.

Pension cost determination assumes a forecasted mix of investment types over the long-term.

• Investment returns in 2018 were below the assumed level of 7.10%;

• Investment returns in 2017 were above the assumed level of 7.10%;

• Investment returns in 2016 were below the assumed level of 7.10%; and

• In 2019, NSP-Minnesota’s expected investment-return assumption is 7.10%.

Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s and NSP-Minnesota’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.

There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.

State agencies also have issued guidelines to the funding of postretirement benefit costs.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

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Plan Assets

The following presents, for each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value:

	Dec. 31, 2018 (a)												Dec. 31, 2017 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV			Total			Level 1			Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	31.8	$	—	$	—	$	—		$	31.8		$	53.4		$	—	$	—	$	—	$	53.4
Commingled funds:	241.0		—		—		271.2			512.2			285.2			—		—		302.4		587.6
Debt securities:	—		143.7		—		—			143.7			—			159.0		—		—		159.0
Equity securities:	29.3		—		—		—			29.3			32.1			—		—		—		32.1
Other	0.5		1.3		—		(8.2		)	(6.4		)	(8.7		)	1.0		—		0.1		$	(7.6	)
Total	$	302.6	$	145.0	$	—	$	263.0		$	710.6		$	362.0		$	160.0	$	—	$	302.5	$	824.5

^(a)  See Note 8 for further information on fair value measurement inputs and methods.

The following presents, for each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value:

	Dec. 31, 2018 (a)										Dec. 31, 2017 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	0.1	$	—	$	—	$	—	$	0.1	$	0.4	$	—	$	—	$	—	$	0.4
Insurance contracts	—		0.3		—		—		0.3		—		0.7		—		—		0.7
Commingled funds	0.8		—		—		0.2		1.0		2.1		—		—		—		2.1
Debt securities	—		1.0		—		—		1.0		—		2.8		—		—		2.8
Equity securities	—		—		—		—		—		0.5		—		—		—		0.5
Total	$	0.9	$	1.3	$	—	$	0.2	$	2.4	$	3.0	$	3.5	$	—	$	—	$	6.5

^(a)  See Note 8 for further information on fair value measurement inputs and methods.

No assets transferred in or out of Level 3 for 2018 or 2017.

Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for NSP-Minnesota are as follows:

	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,035.1		$	1,036.5		$	88.8		$	86.7
Service cost	28.0			27.8			0.2			0.1
Interest cost	35.2			40.7			3.1			3.4
Plan amendments	—			(4.4		)	—			—
Actuarial (gain) loss	(50.8		)	64.1			(9.0		)	5.9
Plan participants’ contributions	—			—			0.4			0.4
Benefit payments (a)	(140.5		)	(129.6		)	(7.5		)	(7.7		)
Obligation at Dec. 31	$	907.0		$	1,035.1		$	76.0		$	88.8
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	824.5		$	783.2		$	6.5		$	3.7
Actual return on plan assets	(36.5		)	110.1			—			—
Employer contributions	63.1			60.7			3.0			10.1
Plan participants’ contributions	—			—			0.4			0.4
Benefit payments	(140.5		)	(129.5		)	(7.5		)	(7.7		)
Fair value of plan assets at Dec. 31	$	710.6		$	824.5		$	2.4		$	6.5
Funded status of plans at Dec. 31	$	(196.4	)	$	(210.6	)	$	(73.6	)	$	(82.3	)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Current assets (liabilities)	$	—		$	—		$	(4.8	)	$	(1.3	)
Noncurrent assets (liabilities)	(196.4		)	(210.6		)	(68.8		)	(81.0		)
Net amounts recognized	$	(196.4	)	$	(210.6	)	$	(73.6	)	$	(82.3	)

^(a)  Includes approximately $105 million of lump-sum benefit payments used in the determination of a settlement charge.

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Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.31	%	3.63	%	4.32	%	3.62	%
Expected average long-term increase in compensation level	3.75	%	3.75	%	N/A		N/A
Mortality table	RP-2014		RP-2014		RP-2014		RP-2014
Health care costs trend rate — initial: Pre-65	N/A		N/A		6.50	%	7.00	%
Health care costs trend rate — initial: Post-65	N/A		N/A		5.30	%	5.50	%
Ultimate trend assumption — initial: Pre-65	N/A		N/A		4.50	%	4.50	%
Ultimate trend assumption — initial: Post-65	N/A		N/A		4.50	%	4.50	%
Years until ultimate trend is reached	N/A		N/A		4		5

The accumulated benefit obligation for the pension plan was $845 million and $969 million as of Dec. 31, 2018 and 2017, respectively.

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit) other than the service cost component is included in other income in the consolidated statement of income.

Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:

	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2018			2017			2016			2018			2017			2016
Service cost	$	28.0		$	27.8		$	28.3		$	0.2		$	0.1		$	0.1
Interest cost	35.2			40.7			45.4			3.1			3.4			3.9
Expected return on plan assets	(58.2		)	(60.1		)	(60.9		)	(0.4		)	(0.2		)	(0.2		)
Amortization of prior service cost	(0.1		)	1.1			0.9			(3.0		)	(3.0		)	(3.0		)
Amortization of net loss	38.5			39.6			36.8			2.4			2.0			1.6
Settlement charge (a)	48.8			48.2			—			—			—			—
Net periodic pension cost	92.2			97.3			50.5			2.3			2.3			2.4
Costs not recognized due to effects of regulation	(66.0		)	(72.2		)	(20.9		)	—			—			—
Net benefit cost recognized for financial reporting	$	26.2		$	25.1		$	29.6		$	2.3		$	2.3		$	2.4
Significant Assumptions Used to Measure Costs:
Discount rate	3.63		%	4.13		%	4.66		%	3.62		%	4.13		%	4.65		%
Expected average long-term increase in compensation level	3.75			3.75			4.00			—			—			—
Expected average long-term rate of return on assets	7.10			7.10			7.10			5.30			5.80			5.80

^(a)  A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of $48.8 million in 2018 and $48.2 million in 2017, which was not recognized due to the effects of regulation.

	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	502.0		$	545.3		$	34.3		$	45.3
Prior service (credit) cost	(1.2		)	(1.3		)	(12.4		)	(15.4		)
Total	$	500.8		$	544.0		$	21.9		$	29.9
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	35.5		$	37.7		$	—		$	—
Noncurrent regulatory assets	465.3			506.3			20.5			28.0
Deferred income taxes	—			—			0.4			0.5
Net-of-tax accumulated other comprehensive income	—			—			1.0			1.4
Total	$	500.8		$	544.0		$	21.9		$	29.9
Measurement date	Dec. 31, 2018			Dec. 31, 2017			Dec. 31, 2018			Dec. 31, 2017

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Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2016 - 2019 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

• $150 million in January 2019, of which $47 million is attributable to NSP-Minnesota;

• $150 million in 2018, of which $63 million was attributable to NSP-Minnesota;

• $162 million in 2017, of which $61 million was attributable to NSP-Minnesota; and,

• $125 million in 2016, of which $49 million was attributable to NSP-Minnesota.

The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Voluntary postretirement funding contributions:

• $11 million in January 2019, of which $7 million is attributable to NSP-Minnesota;

• $11 million in 2018, of which $3 million, was attributable to NSP-Minnesota;

• $20 million in 2017, of which $10 million was attributable to NSP-Minnesota; and,

• $18 million in 2016, of which $9 million was attributable to NSP-Minnesota.

Target asset allocations:

	Pension Benefits				Postretirement Benefits
	2018		2017		2018		2017
Domestic and international equity securities	37	%	38	%	18	%	24	%
Long-duration fixed income and interest rate swap securities	28		23		—		—
Short-to-intermediate fixed income securities	18		21		70		60
Alternative investments	15		16		8		9
Cash	2		2		4		7
Total	100	%	100	%	100	%	100	%

Plan Amendments —Xcel Energy, which includes NSP-Minnesota, amended the Xcel Energy Pension Plan in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2016, the Xcel Energy Pension Plan was amended to change the discount rate basis for lump-sum conversion to annuity participants and annuity conversion to lump-sum participants.

In 2018 and 2017, there were no plan amendments made which affected the benefit obligation.

Projected Benefit Payments

NSP-Minnesota’s projected benefit payments:

(Millions of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2019	$	93.4	$	7.2	$	—	$	7.2
2020	81.2		7.0		—		7.0
2021	80.1		6.7		—		6.7
2022	79.0		6.3		—		6.3
2023	77.2		6.0		—		6.0
2024-2027	342.3		26.0		—		26.0

Defined Contribution Plans

Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for NSP-Minnesota was approximately $12 million in 2018, $12 million in 2017 and $12 million in 2016.

Multiemployer Plans

NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

10.Commitments and Contingencies

Legal

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 complex judgments about future events. Management maintains accruals for 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 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.

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.

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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 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 filed comments agreeing 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.

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 a New England Transmission Owners base ROE order that addressed the D.C. Circuit’s actions on Opinion No. 531. Under a new proposed two step ROE approach, the FERC has 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, CAPM, and Expected Earnings models. The FERC proposes that if necessary, it would then set a new ROE by averaging the results of these models plus a Risk Premium model.

With respect to the MISO TOs, the FERC subsequently made preliminary determinations in a November 2018 order that the MISO 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 compliant period, compared to the previously ordered base ROE of 10.32%. A procedural schedule has been set for the first half of 2019, with the FERC expected to act no earlier than the second half of 2019. NSP-Minnesota has recognized a current refund liability consistent with its best estimate of the final ROE.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for NSP-Minnesota, which are normally recovered through the regulated rate process.

Site Remediation — Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota’s predecessors or other parties have caused environmental contamination.

Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to have sent wastes to that site.

MGP, Landfill or Disposal Sites — NSP-Minnesota is currently investigating or remediating six MGP, landfill or other disposal sites sites across its service territories, and these activities will continue through at least 2019. NSP-Minnesota accrued $6 million as of Dec. 31, 2018, and $19 million as of Dec. 31, 2017 for these sites. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting some portion of costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation —NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste.In 2015, the EPA published the CCR Rule. Litigation was brought challenging the rule in the D.C. Circuit. 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 additional groundwater sampling and will evaluate 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. In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. Litigation is ongoing regarding the deadline for closing or retrofitting these impoundments. The decision will require NSP-Minnesota to expedite closure plans for one impoundment in Minnesota (see ARO removal costs below) and will require the construction of a new impoundment, which is estimated to cost $6 million.

Federal CWA WOTUS Rule —In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. The Rule has been subject to significant litigation and is currently stayed in a portion of the country. NSP-Minnesota cannot estimate potential impacts until the legal and administrative processes are finalized, but expects costs will be recoverable through regulatory mechanisms.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, NSP-Minnesota estimates that ELG compliance will cost approximately $10 million to complete. The EPA, however, is conducting a rulemaking process to potentially revise the effluent limitations and pretreatment standards, which may impact compliance costs. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms.

FederalCWASection 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. NSP-Minnesota estimates the likely cost for complying with impingement and entrainment requirements is approximately $39 million, to be incurred between 2019 and 2028. NSP-Minnesota believes six plants could be required by state regulators to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to $194 million. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms.

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AROs — AROs have been recorded for NSP-Minnesota’s assets. For nuclear assets, the ARO is associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello and PI.

Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was 2.1 billion for 2018 and 2017.

NSP-Minnesota’s AROs were as follows:

	Dec. 31, 2018
(Millions of Dollars)	Jan. 1, 2018		Amounts Settled (a)			Accretion		Cash Flow Revisions (b)			Dec. 31, 2018(c)
Electric
Nuclear	$	1,873.6	$	—		$	94.7	$	—		$	1,968.3
Wind	94.1		—			4.3		6.5			104.9
Steam and other production	64.0		(6.6		)	2.1		(10.3		)	49.2
Distribution	5.8		—			0.2		8.5			14.5
Miscellaneous	1.9		—			—		(0.1		)	1.8
Natural gas
Transmission and distribution	43.6		—			1.8		(7.2		)	38.2
Miscellaneous	0.2		—			—		—			0.2
Common
Miscellaneous	0.7		—			0.1		—			0.8
Total liability	$	2,083.9	$	(6.6	)	$	103.2	$	(2.6	)	$	2,177.9

^(a)  Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

^(b)  In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.

^(c)  There were no ARO amounts incurred in 2018.

	Dec. 31, 2017
(Millions of Dollars)	Jan. 1, 2017		Amounts Settled (a)			Accretion		Cash Flow Revisions (b)			Dec. 31, 2017 (c)
Electric
Nuclear	$	2,249.3	$	—		$	113.8	$	(489.5	)	$	1,873.6
Wind	90.1		—			4.0		—			94.1
Steam and other production	68.5		(4.9		)	2.4		(2.0		)	64.0
Distribution	5.6		—			0.2		—			5.8
Miscellaneous	1.8		—			0.1		—			1.9
Natural gas
Transmission and distribution	35.8		—			1.5		6.3			43.6
Miscellaneous	0.2		—			—		—			0.2
Common
Miscellaneous	1.3		(0.6		)	—		—			0.7
Total liability	$	2,452.6	$	(5.5	)	$	122.0	$	(485.2	)	$	2,083.9

^(a)  Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

^(b)  In 2017, AROs were revised for changes in timing and estimates of cash flows. Nuclear AROs decreased due to updated assumptions in the nuclear triennial filing.

^(c)  There were no ARO amounts incurred in 2017.

Indeterminate AROs —Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2018. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — NSP-Minnesota records a regulatory liability for the plant removal costs that are recovered currently in rates. These removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2018 and 2017 were $485 million and $442 million.

Nuclear Related

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $14.1 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450.0 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.6 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear incident. NSP-Minnesota is subject to assessments of up to $137.6 million per reactor-incident for each of its three licensed reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $20.5 million per reactor-incident during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was effective November 2018.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of approximately $18.0 million for business interruption insurance and $39.0 million for property damage insurance if losses exceed accumulated reserve funds.

Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.

NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 44 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life.

Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.

Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.

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The obligation for decommissioning is expected to be funded 100% by the external decommissioning trust fund. This cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%. Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.

NSP-Minnesota has accumulated $2.1 billion of assets held in external decommissioning trusts in 2018. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements (ARO).

	Regulatory Basis
(Millions of Dollars)	2018			2017
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)	$	3,012.3		$	3,012.3
Effect of escalating costs	538.9			395.7
Estimated decommissioning cost obligation (in current dollars)	3,551.2			3,408.0
Effect of escalating costs to payment date	7,654.3			7,797.5
Estimated future decommissioning costs (undiscounted)	11,205.5			11,205.5
Effect of discounting obligation (using average risk-free interest rate of 3.33% and 2.80% for 2018 and 2017, respectively)	(6,911.5		)	(6,398.1		)
Discounted decommissioning cost obligation	$	4,294.0		$	4,807.4
Assets held in external decommissioning trust	$	2,054.7		$	2,143.3
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation	2,239.3			2,664.1

Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.

Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:

(Millions of Dollars)	2018			2017
Discounted decommissioning cost obligation - regulated basis	$	4,294.0		$	4,807.4
Differences in discount rate and market risk premium	(1,446.4		)	(1,402.8		)
O&M costs not included for GAAP	(879.3		)	(1,041.5		)
ARO differences between 2017 and 2014 cost studies	—			(489.5		)
Nuclear production decommissioning ARO - GAAP	$	1,968.3		$	1,873.6

Decommissioning expenses recognized as a result of regulation:

(Millions of Dollars)	2018		2017		2016
Annual decommissioning recorded as depreciation expense: (a) (b)	$	20.4	$	20.4	$	20.4

^(a)  Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

^(b)  Decommissioning expenses in 2018, 2017 and 2016 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14.0 million.

The 2014 nuclear decommissioning filing approved in 2015 has been used for the regulatory presentation for 2018, 2017 and 2016. The most recent triennial filing was submitted in December 2017 and was approved by the MPUC. It became effective on Jan. 1, 2019 and continued the accrual previously approved in the MPUC order, dated October 2015 from the 2014 filing. The 2020 accrual will be set subsequent to a compliance filing that is expected to be submitted in July 2019.

Leases — NSP-Minnesota leases a variety of equipment and facilities. These leases, primarily for office space, railcars, generating facilities, natural gas pipeline transportation, vehicles, aircraft and power-operated equipment, are accounted for as operating leases.

Total expenses (including capacity payments) under operating lease obligations for NSP-Minnesota and the corresponding capacity payments for PPAs accounted for as operating leases for the year ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Total expense	$	76.2	$	76.9	$	79.1
Capacity payments	62.5		62.7		63.4

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases.

Future commitments under operating leases:

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

^(a)  Amounts do not include PPAs accounted for as executory contracts.

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

Non-Lease PPAs— NSP-Minnesota has entered into PPAs with other utilities and energy suppliers with expiration dates through 2039 for purchased power to meet system load and energy requirements, meet operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments.

Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $52.7 million, $84.1 million and $89.8 million in 2018, 2017 and 2016, respectively.

At Dec. 31, 2018, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)	Capacity		Energy (a)
2019	$	54.0	$	98.7
2020	54.6		109.4
2021	62.2		157.4
2022	61.3		172.9
2023	62.7		176.9
Thereafter	109.5		328.1
Total (b)	$	404.3	$	1,043.4

^(a)  Excludes contingent energy payments for renewable energy PPAs.

^(b)  Includes amounts allocated to NSP-Wisconsin through intercompany charges.

47

Fuel Contracts — NSP-Minnesota has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2019 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases for these contracts as of Dec. 31, 2018:

(Millions of Dollars)	Coal		Nuclear fuel		Natural gas supply		Natural gas storage and transportation
2019	$	194.7	$	127.1	$	43.6	$	107.4
2020	87.4		50.9		1.4		97.5
2021	52.0		99.0		1.4		95.6
2022	34.7		78.5		0.8		92.6
2023	35.1		99.4		—		82.8
Thereafter	3.5		337.1		—		320.7
Total (a)	$	407.4	$	792.0	$	47.2	$	796.6

^(a)  Includes amounts allocated to NSP-Wisconsin through intercompany charges.

VIEs — Under certain PPAs, NSP-Minnesota purchases power from IPPs for which NSP-Minnesota is required to reimburse fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. NSP-Minnesota has determined that certain IPPs are VIEs. NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

NSP-Minnesota evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities.

NSP-Minnesota 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. NSP-Minnesota had approximately 1002 MW and 1,069 MW of capacity under long-term PPAs at Dec. 31, 2018 and 2017, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2027.

Other

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

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

(Millions of Dollars)	Guarantor	Guarantee Amount		Current Exposure		Triggering Event
Guarantee of residual value of assets under the Bank of Tokyo-Mitsubishi Capital Corporation Equipment Leasing Agreement	NSP-Minnesota	$	4.8	$	—	(a)

^(a)  Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term in 2019.

11.    Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2018 and 2017:

	2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(20.9	)		$	0.1		$	(3.7	)		$	(24.5	)
Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0, and $0.3 respectively)	—				(0.1		)	0.6				0.5
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.3, $0, and $0, respectively) (a)	0.7			(a)	—			—				0.7
Amortization of net actuarial loss (net of taxes of $0, $0, and $0.1, respectively)	—				—			0.2			(b)	0.2
Net current period other comprehensive income (loss)	0.7				(0.1		)	0.8				1.4
Accumulated other comprehensive loss at Dec. 31	$	(20.2	)		$	—		$	(2.9	)		$	(23.1	)

	2017
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(18.2	)		$	0.1	$	(2.7	)		$	(20.8	)
Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0, and $0.1, respectively)	0.1				—		(0.5		)		(0.4		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.6, $0, and $0, respectively)	0.9			(a)	—		—				0.9
Amortization of net actuarial loss (net of taxes of $0, $0, and $0.1, respectively)	—				—		0.1			(b)	0.1
Net current period other comprehensive income (loss)	1.0				—		(0.4		)		0.6
Adoption of ASU No. 2018-02 (c)	(3.7		)		—		(0.6		)		(4.3		)
Accumulated other comprehensive (loss) income at Dec. 31	$	(20.9	)		$	0.1	$	(3.7	)		$	(24.5	)

^(a)  Included in interest charges.

^(b)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

^(c)  In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

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12.    Segments and Related Information

Operating results from 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 — 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 costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

NSP-Minnesota’s segment information is as follows:

(Millions of Dollars)	2018			2017			2016
Regulated Electric
Operating revenues (a)	$	4,508.0		$	4,541.8		$	4,404.6
Intersegment revenues	0.8			0.6			0.6
Total operating revenue	$	4,508.8		$	4,542.4		$	4,405.2
Depreciation and amortization	697.8			661.3			554.3
Interest charges and financing costs	199.5			199.8			200.8
Income tax expense	16.4			179.9			215.5
Net income	450.4			462.5			465.4
Regulated Natural Gas
Operating revenues (a)	$	583.1		$	531.9		$	467.4
Intersegment revenues	0.5			0.5			0.5
Total operating revenue	$	583.6		$	532.4		$	467.9
Depreciation and amortization	43.3			38.7			41.8
Interest charges and financing costs	14.8			13.5			13.2
Income tax expense	10.2			10.0			12.0
Net income	34.2			28.4			18.3
All Other
Operating revenues (a)	$	30.8		$	28.3		$	28.3
Depreciation and amortization	0.5			0.6			0.6
Interest charges and financing costs	—			—			—
Income tax expense	0.6			9.8			(3.0		)
Net income	7.7			(0.8		)	5.0
Consolidated Total
Total operating revenue	$	5,123.2		$	5,103.1		$	4,901.4
Reconciling eliminations	(1.3		)	(1.1		)	(1.1		)
Consolidated total revenue	$	5,121.9		$	5,102.0		$	4,900.3
Depreciation and amortization	741.6			700.6			596.7
Interest charges and financing costs	214.3			213.3			214.0
Income tax expense	27.2			199.7			224.5
Net income	492.3			490.1			488.7

^(a)  Operating revenues include $473.7 million, $490.2 million, and $475.5 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 13 for further information.

13. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Minnesota uses the services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 5 for further information.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.

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Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Operating revenues:
Electric	$	473.7	$	490.2	$	475.5
Operating expenses:
Purchased power	61.1		66.8		63.0
Transmission expense	96.8		110.5		107.5
Other operating expenses — paid to Xcel Energy Services Inc.	534.8		539.4		513.0
Interest expense	0.3		—		—

Accounts receivable and payable with affiliates at Dec. 31 were:

	2018				2017
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Wisconsin	$	11.0	$	—	$	17.8	$	—
PSCo	—		17.9		—		7.7
SPS	—		4.7		—		1.0
Other subsidiaries of Xcel Energy Inc.	—		87.1		30.7		71.4
	$	11.0	$	109.7	$	48.5	$	80.1

14. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Millions of Dollars)	March 31, 2018		June 30, 2018		Sept. 30, 2018		Dec. 31, 2018
Operating revenues	$	1,310.8	$	1,187.7	$	1,351.8	$	1,271.6
Operating income	171.4		150.1		259.5		135.5
Net income	111.7		92.4		201.2		87.0

	Quarter Ended
(Millions of Dollars)	March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
Operating revenues	$	1,307.1	$	1,164.9	$	1,355.8	$	1,274.2
Operating income (a)	182.5		173.1		339.7		187.4
Net income	94.2		87.7		229.0		79.3

^(a)  In 2018, NSP-Minnesota implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.

Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A — 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 and chief financial officer, allowing timely decisions regarding required disclosure.

As of Dec. 31, 2018, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the chief executive officer and chief financial officer, of the effectiveness of its disclosure controls and the procedures, the chief executive officer and chief financial officer have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting. NSP-Minnesota maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. NSP-Minnesota has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2018 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, NSP-Minnesota did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

This annual report does not include an attestation report of NSP-Minnesota’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by NSP-Minnesota’s independent registered public accounting firm pursuant to the rules of the SEC that permit NSP-Minnesota to provide only management’s report in this annual report.

Item 9B — Other Information

None.

PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for NSP-Minnesota in accordance with conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13 — Certain Relationships and Related Transactions, and Director Independence

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2019 Annual Meeting of Shareholders, which is incorporated by reference.

Item 14 — Principal Accountant Fees and Services

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm - Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.

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PART IV

Item 15 — Exhibits, Financial Statement Schedules

1	Consolidated Financial Statements:
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2018.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2018, 2017 and 2016.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2018, 2017 and 2016.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2018, 2017 and 2016.
	Consolidated Balance Sheets — As of Dec. 31, 2018 and 2017.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2018, 2017 and 2016.
2	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2018, 2017 and 2016.
3	Exhibits
*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

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) on Aug. 21, 2000)	NSP-Minnesota Form 10-12G dated Oct. 5, 2000	000-31709	3.01
3.02	By-Laws of NSP-Minnesota as Amended and Restated on Jan. 25, 2019
4.01*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds, Supplemental Indentures between NSP-Minnesota and said Trustee	Xcel Energy Inc. Form S-3 dated April 18, 2018	001-03034	4(b)(3)
4.02*	Supplemental Trust Indenture dated June 1, 1995, creating $250 million principal amount of 7.125% First Mortgage Bonds, Series due July 1, 2025	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017	001-03034	4.11
4.03*	Supplemental Trust Indenture dated March 1, 1998, creating $150 million principal amount of 6.5% First Mortgage Bonds, Series due March 1, 2028	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017	001-03034	4.12
4.04*	Supplemental Trust Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)	NSP-Minnesota Form 10-12G dated Oct. 5, 2000	000-31709	4.51
4.05*	Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the issuance of Sr. Debt Securities	Xcel Energy Inc. Form S-3 dated April 18, 2018	001-03034	4(b)(7)
4.06*	Supplemental Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee (Assignment and Assumption of Indenture)	NSP-Minnesota Form 10-12G dated Oct. 5, 2000	000-31709	4.63
4.07*	Supplemental Trust Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250 million principal amount of 5.25% First Mortgage Bonds, Series due July 15, 2035	NSP-Minnesota Form 8-K dated July 14, 2005	001-31387	4.01
4.08*	Supplemental Trust Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400 million principal amount of 6.25% First Mortgage Bonds, Series due June 1, 2036	NSP-Minnesota Form 8-K dated May 18, 2006	001-31387	4.01
4.09*	Supplemental Trust Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee	NSP-Minnesota Form 8-K dated June 19, 2007	001-31387	4.01
4.10*	Supplemental Trust Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and The Bank of New York Mellon Trust Co., NA, as successor Trustee, creating $300 million principal amount of 5.35% First Mortgage Bonds, Series due Nov. 1, 2039	NSP-Minnesota Form 8-K dated Nov. 16, 2009	001-31387	4.01
4.11*	Supplemental Trust Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250 million principal amount of 1.950% First Mortgage Bonds, Series due Aug. 15, 2015 and $250 million principal amount of 4.850% First Mortgage Bonds, Series due Aug. 15, 2040	NSP-Minnesota Form 8-K dated Aug. 4, 2010	001-31387	4.01
4.12*	Supplemental Trust Indenture dated as of Aug. 1, 2012 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $300 million principal amount of 2.15% First Mortgage Bonds, Series due Aug. 15, 2022 and $500 million principal amount of 3.40% First Mortgage Bonds, Series due Aug. 15, 2042	NSP-Minnesota Form 8-K dated Aug. 13, 2012	001-31387	4.01
4.13*	Supplemental Trust Indenture dated as of May 1, 2013 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $400 million principal amount of 2.60% First Mortgage Bonds, Series due May 15, 2023	NSP-Minnesota Form 8-K dated May 20, 2013	001-31387	4.01
4.14*	Supplemental Trust Indenture dated as of May 1, 2014 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300 million principal amount of 4.125% First Mortgage Bonds, Series due May 15, 2044. (Exhibit 4.01 to NSP-Minnesota Form 8-K dated May 13, 2014 (file no. 001-31387))	NSP-Minnesota Form 8-K dated May 13, 2014	001-31387	4.01

51

4.15*	Supplemental Indenture dated as of Aug. 1, 2015 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300 million principal amount of 2.20% First Mortgage Bonds, Series due Aug. 15, 2020 and $300 million principal amount of 4.00% First Mortgage Bonds, Series due Aug. 15, 2045	NSP-Minnesota Form 8-K dated Aug. 11, 2015	001-31387	4.01
4.16*	Supplemental Trust Indenture dated as of May 1, 2016 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $350 million principal amount of 3.600% First Mortgage Bonds, Series due May 15, 2046	NSP-Minnesota Form 8-K dated May 31, 2016	001-31387	4.01
4.17*	Supplemental Indenture dated as of Sept. 1, 2017 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor trustee, creating $600 million principal amount of 3.60% First Mortgage Bonds, Series due Sept. 15, 2047	NSP-Minnesota Form 8-K dated Sept. 13, 2017	001-31387	4.01
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.02
10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Amendment and Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.05
10.03*+	Xcel Energy Inc. Non-Employee Directors Deferred Compensation Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.08
10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies	Xcel Energy Inc. Form U5B dated Nov. 16, 2000	001-03034	H-1
10.05*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.17
10.06*	Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota	NSP-Wisconsin Form S-4 dated Jan. 21, 2004	333-112033	10.01
10.07*+	First Amendment to Exhibit 10.02 dated Aug. 26, 2009	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009	001-03034	10.06
10.08*+	Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009	001-03034	10.08
10.09*+	Xcel Energy Inc. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010	001-03034	Schedule 14A
10.10*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010)	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010	001-03034	Schedule 14A
10.11*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011	Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011	001-03034	Schedule 14A
10.12*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.07
10.13*+	First Amendment to Exhibit 10.12 effective Nov. 29, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	001-03034	10.17
10.14*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	001-03034	10.18
10.15*+	First Amendment to Exhibit 10.09 dated Feb. 20, 2013	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013	001-03034	10.01
10.16*+	Fourth Amendment to Exhibit 10.02 dated Feb. 20, 2013	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013	001-03034	10.02
10.17*+	First Amendment to Exhibit 10.10 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	001-03034	10.21
10.18*+	Second Amendment to Exhibit 10.12 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	001-03034	10.22
10.19*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	001-03034	10.23
10.20*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2015	001-03034	Schedule 14A
10.21*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated May 20, 2015	001-03034	10.02
10.22*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions under the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated May 20, 2015	001-03034	10.03
10.23*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan Form of Award Agreement	Xcel Energy inc. Form 10-K for the year ended Dec. 31, 2015	001-03034	10.28
10.24*+	Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy inc. Form 10-K for the year ended Dec. 31, 2015	001-03034	10.29
10.25*+	Fifth Amendment Exhibit 10.02 dated May 3, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016	001-03034	10.01
10.26*	Second Amendment and Restated Credit Agreement, dated as of June 20, 2016 among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and the Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents	Xcel Energy Inc. Form 8-K dated June 20, 2016	001-03034	99.02
10.27*+	Third Amendment to Exhibit 10.12 dated Sept. 30, 2016	Xcel Energy inc. Form 10-Q for the quarter ended Sept. 30, 2016	001-03034	10.01
10.28*+	Form of Xcel Energy, Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions under the Xcel Energy inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2016	001-03034	10.27

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10.29*+	Fourth Amendment to Exhibit 10.12 dated Oct. 23, 2017	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017	001-03034	10.1
10.30*+	Sixth Amendment to Exhibit 10.02 dated Feb. 22, 2018	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017	001-03034	10.30
10.31*+	Seventh Amendment to Exhibit 10.02 dated May 7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	001-03034	10.01
10.32*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.34
10.33*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.35
10.34*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.36
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification 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 certification 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.
101	The following materials from NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2018 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) Notes to Consolidated Financial Statements, (vii) document and entity information, and (viii) Schedule II.

SCHEDULE II

NSP-MINNESOTA AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31

	Allowance for bad debts
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	21.3		$	20.0		$	20.8
Additions Charged to Costs and Expenses	16.2			15.7			15.0
Additions Charged to Other Accounts (a)	4.1			3.8			4.2
Deductions from Reserves (b)	(18.1		)	(18.2		)	(20.0		)
Balance at Dec. 31	$	23.5		$	21.3		$	20.0

^(a)  Recovery of amounts previously written off.

^(b)  Deductions relate primarily to bad debt write-offs.

Item 16 — Form 10-K Summary

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.

	NORTHERN STATES POWER COMPANY (A MINNESOTA CORPORATION)
Feb. 22, 2019	/s/ ROBERT C. FRENZEL
	Robert C. Frenzel
	Executive Vice President, Chief Financial Officer and Director
	(Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.

/s/ BEN FOWKE	/s/ CHRISTOPHER B. CLARK
Ben Fowke	Christopher B. Clark
Chairman, Chief Executive Officer and Director	President and Director
(Principal Executive Officer)
/s/ ROBERT C. FRENZEL	/s/ JEFFREY S. SAVAGE
Robert C. Frenzel	Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director	Senior Vice President, Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ DAVID L. EVES
David L. Eves
Executive Vice President and Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

NSP-Minnesota has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

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EX-3.02

Exhibit 3.02

NORTHERN STATES POWER COMPANY

(a Minnesota corporation)

AMENDED AND RESTATED BYLAWS

(as amended and restated January 25, 2019)

ARTICLE IOFFICES; CORPORATE SEAL

Section 1.1.Registered Office. The registered office of the Company shall be at the address specified in the Articles of Incorporation or any amendment or restatement thereof or in a certificate of change of registered office filed with the Secretary of State of Minnesota.

Section 1.2.Other Offices. The Company may also have offices at such other places both within and without the State of Minnesota as the Board of Directors may from time to time determine or the business of the Company may require.

Section 1.3.Corporate Seal. The Company may, but need not, have a corporate seal. If the Company has a corporate seal, the use of the seal by the Company on a document is not required, and the use or nonuse of the seal does not affect the validity, recordability, or enforceability of a document or act. The seal need include only the word "Seal," but it may also include a part or all of the name of the Company and a combination, derivation, or abbreviation of either or both of the phrases "a Minnesota Corporation" and "Corporate Seal." If a corporate seal is used, it or a facsimile of it may be affixed, engraved, printed, placed, stamped with indelible ink, or in any other manner reproduced on any document.

ARTICLE IISHAREHOLDERS

Section 2.1.In General.Except as required by Section 2.6, all meetings of the shareholders shall be held at the registered office of the Company or at such other place either within or without the State of Minnesota as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting.

Section 2.2.Regular Meetings. Regular meetings of shareholders may be held on an annual or other less frequent periodic basis, but need not be held unless required by the Articles of Incorporation, these Bylaws, or the laws of the State of Minnesota.

Section 2.3.Business at Regular Meeting. At each regular meeting of shareholders there shall be an election of directors. No other particular business is

required to be transacted at a regular meeting. Any business appropriate for action by the shareholders may be transacted at a regular meeting.

Section 2.4.Special Meetings. Special meetings of the shareholders may be called for any purpose or purposes at any time, by the chief executive officer, the chief financial officer, two or more directors, a person authorized in the Articles of Incorporation or these Bylaws to call special meetings, or a shareholder or shareholders holding ten percent or more of the voting shares.

Section 2.5.Business at Special Meetings. The business transacted at a special meeting shall be limited to the purposes stated in the notice of the meeting. Any business transacted at a special meeting that is not included in those stated purposes is voidable by or on behalf of the Company, unless all of the shareholders have waived notice of the meeting in accordance with Section 2.7.

Section 2.6.Notice of Meeting. Written notice of all meetings of shareholders stating the place, date, and hour of the meeting and, in the case of special meetings, the purpose or purposes for which the meeting is called, shall be given to each shareholder entitled to vote at such meeting not less than 48 hours before the date of the meeting, except that a meeting called by or at the demand of a shareholder or shareholders shall be held in the county where the principal executive office of the Company is located.

Section 2.7.Waiver; Objections. A shareholder may waive notice of a meeting of shareholders. A waiver of notice by a shareholder entitled to notice is effective whether given before, at, or after the meeting, and whether given in writing (including by authenticated electronic communication), orally, or by attendance. Attendance by a shareholder at a meeting is a waiver of notice of that meeting, except where the shareholder objects at the beginning of the meeting to the transaction of business because the meeting is not lawfully called or convened, or objects before a vote on an item of business because the item may not lawfully be considered at that meeting and does not participate in the consideration of the item at that meeting.

Section 2.8.Record Date. The Board of Directors may fix a date not more than 60 days before the date of a meeting of shareholders as the date for the determination of the holders of voting shares entitled to notice of and to vote at such meeting. When a date is so fixed, only shareholders on that date are entitled to notice and permitted to vote at that meeting of shareholders.

Section 2.9.Quorum. The holders of a majority of the voting power of the shares entitled to vote at a meeting present in person or by proxy at the meeting are a quorum for the transaction of business, unless a larger or smaller proportion or number is provided in the Articles of Incorporation. If a quorum is present when a duly called or held meeting is convened, the shareholders present may continue to transact business until adjournment, even though the withdrawal of a number of shareholders originally present leaves less than the proportion or number otherwise required for a quorum.

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Section 2.10.Adjourned Meetings. In the absence of a quorum, any meeting may be adjourned from time to time. If any meeting of the shareholders is adjourned to another time (not more than 120 days after the date fixed for the original meeting) or place, no notice of the date, time, and place of such adjourned meeting need be given other than by announcement at the time of adjournment.

Section 2.11.Majority Vote Required. The shareholders shall take action by the affirmative vote of the holders of a majority of the voting power of the shares present, except where a larger proportion or number is required by the Articles of Incorporation, these Bylaws, or the laws of the State of Minnesota.

Section 2.12.Voting by Class. In any case where a class or series of shares is entitled by the Articles of Incorporation, the laws of the State of Minnesota, or the terms of the shares to vote as a class or series, the matter being voted upon must also receive the affirmative vote of the holders of the same proportion of the shares of that class or series as is required pursuant to Section 2.11.

Section 2.13.Voting Power. Unless otherwise provided in the Articles of Incorporation or in the terms of the shares, a shareholder has one vote for each share held.

Section 2.14.Jointly Owned Shares. Shares owned by two or more shareholders may be voted by any one of them unless the Company receives written notice from any one of them denying the authority of that person to vote those shares.

Section 2.15.Shareholder Management. The holders of the voting shares of the Company may, by unanimous affirmative vote, take any action that the Board of Directors is required or permitted to take or that the shareholders are permitted to take after action or approval of the Board.

Section 2.16.Proxies. A shareholder may cast or authorize the casting of a vote by filing a written appointment of a proxy with an officer of the Company at or before the meeting at which the appointment is to be effective. An appointment of a proxy for shares held jointly by two or more shareholders is valid if signed by any one of them, unless the Company receives from any one of those shareholders written notice either denying the authority of that person to appoint a proxy or appointing a different proxy.

Section 2.17.Action Without a Meeting. An action required or permitted to be taken at a meeting of the shareholders may be taken without a meeting by written action signed, or consented to by authenticated electronic communication, by all of the shareholders entitled to a vote on such action. The written action is effective when it has been signed, or consented to, by all of those shareholders, unless a different time is provided in the written action.

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ARTICLE III

DIRECTORS

Section 3.1.Number and Election. The Board of Directors shall consist of one or more directors. The number of directors shall be determined by the shareholders who shall, at each regular meeting, fix the number of directors and elect the number so fixed. Except as provided in Section 3.2, each director shall hold office until his successor is elected and qualifies or until his earlier death, disqualification, resignation or removal. Directors shall be natural persons but need not be shareholders.

Section 3.2.Vacancies and New Directorships. Unless different rules for filling vacancies are provided for in the Articles of Incorporation, vacancies on the Board resulting from the death, disqualification, resignation, or removal of a director may be filled by the affirmative vote of a majority of the remaining directors, even though less than a quorum, and vacancies on the Board resulting from newly created directorships may be filled by the affirmative vote of a majority of the directors serving at the time of the increase. Each director elected to fill a vacancy holds office until a qualified successor is elected by the shareholders at the next regular meeting or special meeting of the shareholders.

Section 3.3.Powers. Except as may otherwise be provided by Section 2.17, the business and affairs of the Company shall be managed by or under the direction of a Board of Directors, which may exercise all such powers of the Company and do all such lawful acts and things as are not by the Articles of Incorporation, these Bylaws, or the laws of the State of Minnesota required to be exercised or done by the shareholders.

Section 3.4.Time and Place of Meetings. Regular meetings of the Board of Directors may be held with and without notice, from time to time at any place, within or without the State of Minnesota, that the Board of Directors may select or by any means described in Section 3.5. If the Board of Directors fails to select a place for a meeting, the meeting shall be held at the principal executive office of the Company.

Section 3.5.Electronic Meetings. A conference among directors by any means of communication through which the directors may simultaneously hear each other during the conference constitutes a board meeting, if the same notice is given of the conference as would be required by Section 3.7 for a meeting, and if the number of directors participating in the conference would be sufficient to constitute a quorum at a meeting. Participation in a meeting by that means constitutes presence in person at the meeting. A director may participate in a board meeting not described above by any means of communication through which the director, other directors so participating, and all directors physically present at the meeting may simultaneously hear each other

4

during the meeting. Participation in a meeting by that means constitutes presence in person at the meeting.

Section 3.6.Other Meetings. Other meetings of the Board may be called by a director or by the chief executive officer of the Company on 24 hours’ notice to all directors, of the date, time and place of the meeting. The notice shall be given to each director by mail, electronic mail, facsimile, telephone, personal service or any other means as may then be permitted by law and need not state the purpose of the meeting. If the date, time, and place of a board meeting have been announced at a previous meeting of the Board, no notice is required.

Section 3.7.Quorum. A majority, or a larger or smaller proportion or number provided in the Articles of Incorporation, of the directors currently holding office present at a meeting is a quorum for the transaction of business.

Section 3.8.Adjourned Meetings. In the absence of a quorum, any meeting may be adjourned from time to time. If any meeting of the Board of Directors is adjourned to another time or place, no notice of such adjourned meeting need be given other than by announcement at the time of adjournment.

Section 3.9.Board Action. The Board shall take action by the affirmative vote of a majority of directors present at a duly held meeting, except where the affirmative vote of a larger proportion or number is required by the Articles of Incorporation, these Bylaws, or the laws of the State of Minnesota. If the Articles of Incorporation require a larger proportion or number than is required by the laws of the State of Minnesota for a particular action, the Articles of Incorporation shall control.

Section 3.10.Waiver of Notice. A director may waive notice of a meeting of the Board. A waiver of notice by a director entitled to notice is effective whether given before, at, or after the meeting, and whether given in writing, orally, or by attendance. Attendance by a director at a meeting is a waiver of notice of that meeting, except where the director objects at the beginning of the meeting to the transaction of business because the meeting is not lawfully called or convened and does not participate thereafter in the meeting.

Section 3.11.Absent Directors. A director may give advance written consent or opposition to a proposal to be acted on at a board meeting. If the director is not present at the meeting, consent or opposition to a proposal does not constitute presence for purposes of determining the existence of a quorum, but consent or opposition shall be counted as a vote in favor of or against the proposal and shall be entered in the minutes or other record of action at the meeting, if the proposal acted on at the meeting is substantially the same or has substantially the same effect as the proposal to which the director has consented or objected.

Section 3.12.Committees. A resolution approved by the affirmative vote of a majority of the entire Board of Directors may establish committees having the authority

5

of the Board in the management of the business of the Company to the extent provided in the resolution. Committee members shall be natural persons. Unless the Articles of Incorporation provide for a different membership, a committee shall consist of one or more persons, who need not be directors, appointed by affirmative vote of a majority of the directors present. A majority of the members of the committee present at a meeting is a quorum for the transaction of business, unless a larger or small proportion or number is provided in the Articles of Incorporation, these Bylaws, or in a resolution approved by the affirmative vote of a majority of the directors present. Minutes, if any, of committee meetings shall be made available upon request to members of the committee and to any director.

Section 3.13.Action Without a Meeting. An action required or permitted to be taken at a board meeting or by a lawfully constituted committee thereof may be taken by written action signed, or consented to by authenticated electronic communication, by all of the directors or by all of the members of such committee, unless the action need not be approved by the shareholders and the Articles of Incorporation so provide, in which case, the action may be taken by written action signed, or consented to by authenticated electronic communication, by the number of directors that would be required to take the same action at a meeting of the Board of Directors or the committee at which all directors or committee members were present. The written action is effective when signed or consented to by the required number of directors or committee members unless a different effective time is provided in the written action. When written action is permitted to be taken by less than all directors or committee members, all directors and committee members shall be notified immediately of its text and effective date.

ARTICLE IV

OFFICERS

Section 4.1.Election of Required Officers. The Company shall have one or more natural persons exercising the functions of the offices of chief executive officer and chief financial officers.

Section 4.2.Other Officers. The Board of Directors may elect or appoint any other officers or agents the Board deems necessary for the operation and management of the Company, each of whom shall have the powers, rights, duties and responsibilities usually incident to the office or as otherwise provided for in these bylaws or determined by the Board of Directors, the chairman or the officer to whom he or she reports.

Section 4.3.Multiple Offices. Any number of offices or functions of those offices may be held or exercised by the same person. If a document must be signed by person holding different offices or functions and a person holds or exercises more than one of those offices or functions, that person may sign the document in more

6

than one capacity, but only if the document indicates each capacity in which the person signs.

Section 4.4.Tenure, Removal, or Vacancy. Each officer shall hold office until his successor is elected and qualifies, or until his earlier death, disqualification, resignation, or removal. An officer may be removed at any time, with or without cause, by a resolution approved by the affirmative vote of a majority of the directors present. Such removal, however, shall be without prejudice to any contract rights of the officer. Any officer may resign at any time by giving written notice to the Company.

Section 4.5.Duties of Chief Executive Officer. The chief executive officer shall have general active management of the business of the Company; in the absence of the chairman, preside at all meetings of the shareholders and at all meetings of the Board of Directors; see that all orders and resolutions of the Board are carried into effect; and perform other duties as may be prescribed by the Board.

Section 4.6.Duties of Chief Financial Officer. The chief financial officer shall keep accurate financial records for the Company, deposit all money, drafts, and checks in the name of and to the credit of the Company in the banks and depositories designated by the Board; endorse for deposit all notes, checks, and drafts received by the Company as ordered by the Board of Directors, making proper vouchers therefor; disburse corporate funds and issue checks and drafts in the name of the Company, as ordered by the Board; render to the chief executive officer and the Board, whenever requested, an account of all transactions by the chief financial officer and of the financial condition of the Company; and perform other duties prescribed by the Board or by the chief executive officer.

Section 4.7.Duties of Chairman of the Board. The Chairman of the Board, if there be one, shall, when present, preside at all meetings of the shareholders and the Board of Directors and shall perform such duties and have such powers as the Board of Directors may from time to time prescribe.

Section 4.8.Duties of President. Unless otherwise determined by the Board of Directors, the president, if designated, shall be the chief executive officer of the Company. If a person other than the chief executive officer is designated as president, the president shall perform such duties as the Board, the chairman or the chief executive officer may from time to time determine.

Section 4.9.Duties of Vice Presidents. Any one or more of the vice presidents may be designated by the Board as a vice president, an executive vice president or a senior vice president or as otherwise determined by the Board, and each vice president shall have such powers and perform such duties as may from time to time be assigned to them respectively by the Board of Directors, the chairman or the chief executive officer.

7

Section 4.10.Duties of Secretary. The secretary shall attend all meetings of the Board of Directors and of the shareholders and record all the proceedings of all such meetings in a book to be kept for that purpose and shall perform like duties for any committee appointed by the Board when so directed by the chief executive officer; give, or cause to be given, notice of all meetings of the shareholders and, when required, meetings of the Board of Directors; and have custody of the corporate seal of the Company, if there be one, and he, or an assistant secretary, shall have authority to affix the same to any instrument requiring it and, when so affixed, it may be attested by his signature or by the signature of such assistant secretary. The Board of Directors may give general authority to any other officer to affix the seal of the Company, if there be one, and to attest the affixing by his signature. The secretary shall perform such other duties and have such other powers as the Board of Directors, the chairman or the chief executive officer shall from time to time prescribe.

Section 4.11.Duties of Assistant Secretary. The assistant secretary, if there be one, shall, in the absence of the secretary or in the event of the secretary’s inability or refusal to act, perform the duties and exercise the powers of the secretary and shall perform such other duties and have such other powers as the Board of Directors, the chairman, chief executive officer, chief financial officer or the secretary may from time to time prescribe.

Section 4.12.Duties of Controller. The controller shall establish and enforce accounting policies and procedures, and establish and implement internal accounting control practices and systems to preserve the integrity and accuracy of Company’s books of accounts. The controller shall perform such other duties as the Board of Directors, the chairman, chief executive officer or chief financial officer may from time to time prescribe or require.    

Section 4.13.Duties of Treasurer. The treasurer, if there be one, shall perform such duties and have such powers as the Board of Directors, the chairman, chief executive officer or the chief financial officer may from time to time prescribe.

Section 4.14.Duties of Assistant Treasurer. The assistant treasurer, if there be one, shall, in the absence of the treasurer or in the event of the treasurer’s inability or refusal to act, perform the duties and exercise the powers of the treasurer and shall perform such other duties and have such other powers as the Board of Directors, the chairman, chief executive officer, chief financial officer or the treasurer may from time to time prescribe.

Section 4.15.Delegation of Duties. Each officer shall have the authority and shall perform the specific duties reflected under the officer titles noted in sections 4.5 – 4.14 above. In addition they shall perform the duties as may be assigned by the Board of Directors, the Chairman of the Board, or the President, or as shall be conferred or required by law or these Bylaws, or as shall be normally incidental to the office. Unless prohibited by the Board, an officer may, without the approval of the Board, delegate in writing to any other person some or all of the duties and powers of his or her office to

8

other persons. The president, the chief executive officer, the chief financial officer, any vice president of the Company, and any other person or persons pursuant to delegated authority or as may be designated or authorized from time to time by the Board of the chief executive officer may execute and deliver contracts, deeds, mortgages, notes checks, conveyances, releases of mortgages and other instruments on behalf of the Company and otherwise may bind the Company.

ARTICLE V

CERTIFICATES OF SHARES

Section 5.1.Uncertificated Shares. The shares of the Company may be certificated or uncertificated.

Section 5.2.Certificates. Every share certificate of the Company shall be signed by or in the name of the Company by an officer, certifying the number of shares represented by such certificate.

Section 5.3.Facsimile Signatures. If a person signs or has a facsimile signature placed upon a certificate while an officer, transfer agent, or registrar of a corporation, the certificate may be issued by the Company, even if the person has ceased to have that capacity before the certificate is issued, with the same effect as if the person had that capacity at the date of its issue.

Section 5.4.New Certificates. The Board of Directors may direct a new certificate or certificates to be issued in place of any certificate or certificates theretofore issued by the Company alleged to have been lost, stolen, or destroyed upon the making of an affidavit of that fact by the person claiming the certificate to be lost, stolen, or destroyed. When authorizing such issue of a new certificate or certificates, the Board of Directors may, in its own discretion and as a condition precedent to the issuance thereof, require the owner of such lost, stolen, or destroyed certificate or certificates, or his legal representative, to advertise the same in such manner as it shall require and to give the Company a bond in such sum as it may direct as indemnity against any claim that may be made against the Company with respect to the certificate alleged to have been lost, stolen, or destroyed.

Section 5.5.Transfer, Fractional Shares. Upon surrender to the Company or the transfer agent of the Company of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, it shall be the duty of the Company to issue a new certificate to the person entitled thereto, cancel the old certificate, and record the transaction upon its books. Transfers of fractional shares shall not be made nor shall certificates for fractional shares be issued.

9

ARTICLE VI

GENERAL PROVISIONS

Section 6.1.Manner of Amendment. These Bylaws may be altered, amended, or repealed or new Bylaws may be adopted by the shareholders or by the Board of Directors, subject to the power of the shareholders exercisable in the manner provided by the laws of the State of Minnesota to adopt, amend, or repeal Bylaws adopted, amended, or repealed by the Board.

Section 6.2.Dividends. Dividends on the shares of the Company may be declared by the Board of Directors at any regular or special meeting, pursuant to law. Dividends may be paid in cash, in property, or in shares of the Company.

Section 6.3.Voting of Shares of Other Corporations. The shares of any other corporation owned by this corporation may be voted at any meeting of the shareholders of such other corporation by such proxy as the Board of Directors of this corporation may appoint, or if no such appointment be made, by the chief executive officer.

Section 6.4.Indemnification. The Company shall indemnify any person made or threatened to be made a party to a proceeding by reason of the former or present official capacity of the person acting for the Company or acting in an official capacity with another entity at the direction or request of the Company to the full extent permitted by the laws of the State of Minnesota. The indemnification provided under these Bylaws shall inure to the benefit of the heirs, executors, administrators and personal representatives of any person acting in an official capacity for the Company. The Company may purchase and maintain insurance on behalf of a person in that person's official capacity, whether or not the Company would be required by law to indemnify the person against the liability.

10

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-224333-04  on Form S-3 of our report dated February 22, 2019, relating to the consolidated financial statements and financial statement schedule of Northern States Power Company, a Minnesota corporation, and subsidiaries appearing in this Annual Report on Form 10-K of Northern States Power Company, a Minnesota corporation, for the year ended December 31, 2018.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2019

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

1. I have reviewed this report on Form 10-K of Northern States Power Company (a Minnesota corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Feb. 22, 2019

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Robert C. Frenzel, certify that:

1. I have reviewed this report on Form 10-K of Northern States Power Company (a Minnesota corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Feb. 22, 2019

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Northern States Power Company, a Minnesota corporation (NSP-Minnesota) on Form 10-K for the year ended Dec. 31, 2018, as filed with the SEC on the date hereof (Form 10-K), each of the undersigned officers of NSP-Minnesota certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of NSP-Minnesota as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 22, 2019

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NSP-Minnesota and will be retained by NSP-Minnesota and furnished to the SEC or its staff upon request.

1

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 22, 2019	Jun. 29, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN STATES POWER CO
Entity Central Index Key	0001123852
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		1,000,000
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating revenues
Total operating revenues	$ 5,121,900	$ 5,102,000	$ 4,900,300
Operating expenses
Cost of natural gas sold and transported	345,100	301,800	252,800
Cost of sales — other	19,700	18,100	20,000
Operating and maintenance expenses	1,223,300	1,198,300	1,232,200
Conservation program expenses	118,000	120,100	97,900
Depreciation and amortization	741,600	700,600	596,700
Taxes (other than income taxes)	256,600	253,500	246,000
Total operating expenses	4,405,400	4,219,300	3,988,200
Operating income	716,500	882,700	912,100
Interest charges and financing costs
Interest charges — includes other financing costs of $7.4, $7.3 and $7.1 respectively	226,800	228,400	226,500
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(12,500)	(15,100)	(12,500)
Total interest charges and financing costs	214,300	213,300	214,000
Related Party Transaction, Electric Domestic Regulated Revenue		490,200	475,500
Other income, net	(6,500)	(9,100)	(12,600)
Allowance for funds used during construction — equity	23,800	29,500	27,700
Income before income taxes	519,500	689,800	713,200
Income taxes	27,200	199,700	224,500
Net income	492,300	490,100	488,700
Electricity, US Regulated [Member]
Operating expenses
Cost of Goods and Services Sold	1,701,100	1,626,900	1,542,600
Natural Gas, US Regulated [Member]
Operating revenues
Total operating revenues	583,100	531,900	467,400
Product and Service, Other [Member]
Operating revenues
Total operating revenues	30,800	28,400	28,300
Related Party Transaction, Electric Domestic Regulated Revenue [Member]
Operating revenues
Total operating revenues	473,700	490,200	475,500
Non-Related Party Transaction, Electric Domestic Regulated Revenue [Member] | Electricity, US Regulated [Member]
Operating revenues
Total operating revenues	$ 4,034,300	$ 4,051,500	$ 3,929,100

XML

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Interest charges and financing costs
Other financing costs	$ 7,290	$ 7,149	$ 6,710

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Comprehensive income:
Net income	$ 492.3	$ 490.1	$ 488.7
Pension and retiree medical benefits:
Net pension and retiree medical benefits gains (losses) arising during the period, net of tax of $0.3, $(0.4) and $(0.5), respectively	0.6	(0.5)	(0.7)
Amortization of losses included in net periodic benefit cost, net of tax of $0.1, $0.1 and $0, respectively	0.2	0.1	0.1
Total pension and retiree medical benefits, net of tax	0.8	(0.4)	(0.6)
Derivative instruments:
Net fair value increase, net of tax of $0, $0 and $0, respectively	0.0	0.1	0.0
Reclassification of losses to net income, net of tax of $0.3, $0.6 and $0.6, respectively	0.7	0.9	0.9
Total derivative instruments, net of tax	0.7	1.0	0.9
Net fair value decrease, net of tax of $0, $0 and $0, respectively	(0.1)	0.0	0.0
Other comprehensive income	1.4	0.6	0.3
Comprehensive income	$ 493.7	$ 490.7	$ 489.0

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension and retiree medical benefits:
Net pension and retiree medical benefit gains arising during the period, tax	$ 300	$ (400)	$ (500)
Amortization of losses included in net periodic benefit cost, tax	100	100	0
Derivative instruments:
Net fair value (decrease) increase, tax	0	0	0
Reclassification of losses to net income, tax	300	600	600
Income taxes	27,200	199,700	224,500
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	0	0	$ 0
Amounts Reclassified from Accumulated Other Comprehensive Loss
Derivative instruments:
Income taxes	0	0
Reclassification from AOCI, Current Period, Tax	0	0
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	0	0
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Derivative instruments:
Income taxes	300	600
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	0	0
Defined Benefit Pension and Postretirement Items
Pension and retiree medical benefits:
Net pension and retiree medical benefit gains arising during the period, tax	300	100
Derivative instruments:
Reclassification from AOCI, Current Period, Tax	$ 100	$ 100

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities
Net income	$ 492,300	$ 490,100	$ 488,700
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	748,100	707,000	602,900
Nuclear fuel amortization	121,900	114,400	117,000
Deferred income taxes	41,300	193,200	196,200
Allowance for equity funds used during construction	(23,800)	(29,500)	(27,700)
Provision for bad debts	16,200	15,700	15,000
Net realized and unrealized hedging and derivative transactions	27,000	(2,800)	3,700
Changes in operating assets and liabilities:
Accounts receivable	(42,700)	(29,800)	(53,100)
Accrued unbilled revenues	7,400	(18,100)	(32,500)
Inventories	(21,400)	7,600	(1,100)
Other current assets	94,400	(25,300)	(17,000)
Accounts payable	10,500	46,500	24,100
Net regulatory assets and liabilities	182,300	(36,400)	46,900
Other current liabilities	(64,000)	(71,800)	19,100
Pension and other employee benefit obligations	(75,800)	(56,700)	(42,300)
Other, net	(31,500)	(31,300)	(35,000)
Net cash provided by operating activities	1,482,200	1,272,800	1,304,900
Investing activities
Utility capital/construction expenditures	(1,149,700)	(987,200)	(1,176,800)
Purchases of investment securities	(852,900)	(1,690,500)	(506,300)
Proceeds from the sale of investment securities	832,600	1,668,900	478,900
Investments in utility money pool arrangement	(805,000)	(122,000)	(747,500)
Repayments from utility money pool arrangement	805,000	122,000	747,500
Other, net	(3,500)	(3,500)	(1,000)
Net cash used in investing activities	(1,173,500)	(1,012,300)	(1,205,200)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	130,000	(65,000)	(138,000)
Borrowings under utility money pool arrangement	479,000	838,000	424,000
Repayments under utility money pool arrangement	(564,000)	(753,000)	(424,000)
Proceeds from issuance of long-term debt	0	585,200	342,500
Repayments of long-term debt, including reacquisition premiums	0	(507,900)	0
Capital contributions from parent	108,800	145,000	96,700
Dividends paid to parent	(456,300)	(506,600)	(395,900)
Net cash used in by financing activities	(302,500)	(264,300)	(94,700)
Net change in cash and cash equivalents	6,200	(3,800)	5,000
Cash and cash equivalents at beginning of period	43,800	47,600
Cash and cash equivalents at end of period	50,000	43,800	47,600
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(207,400)	(214,200)	(201,400)
Cash received (paid) for income taxes, net	(89,000)	70,900	39,000
Supplemental disclosure of non-cash investing transactions:
Accrued property, plant and equipment additions	92,500	93,100	120,800
Allowance for equity funds used during construction	23,800	29,500	27,700
Inventory transfers to plant, property and equipment	$ 60,800	$ 17,300	$ 35,100

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents		$ 50.0	$ 43.8
Accounts receivable, net		380.9	345.1
Accounts receivable from affiliates		11.0	48.5
Accrued unbilled revenues		270.3	277.7
Inventories		299.4	337.7
Regulatory assets		280.3	276.4
Derivative instruments		25.8	25.2
Prepaid taxes		0.0	79.1
Prepayments and other		28.9	43.7
Total current assets		1,346.6	1,477.2
Property, plant and equipment		13,541.7	13,033.6
Other assets
Nuclear decommissioning fund and other investments		2,107.2	2,192.4
Regulatory assets		1,454.1	1,190.4
Derivative instruments		17.0	28.1
Other		3.3	4.1
Total other assets		3,581.6	3,415.0
Total assets		18,469.9	17,925.8
Current liabilities
Short-term debt		150.0	20.0
Borrowings under utility money pool arrangement		0.0	85.0
Accounts payable		393.6	368.3
Accounts payable to affiliates		109.7	80.1
Regulatory liabilities	[1]	262.4	83.4
Taxes accrued		230.1	229.3
Accrued interest		67.2	65.9
Dividends payable to parent		82.7	98.7
Derivative instruments		16.5	17.7
Customer Deposits, Current		53.7	95.4
Other		154.8	153.0
Total current liabilities		1,520.7	1,296.8
Deferred credits and other liabilities
Deferred income taxes		1,682.4	1,612.3
Deferred investment tax credits		21.1	22.5
Regulatory liabilities	[1]	1,984.7	1,978.5
Asset retirement obligations		2,177.9	2,083.9
Derivative instruments		112.2	102.7
Pension and employee benefit obligations		305.1	331.1
Other		155.5	89.4
Total deferred credits and other liabilities		6,438.9	6,220.4
Capitalization
Long-term debt		4,937.2	4,933.0
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2018 and 2017, respectively		0.0	0.0
Additional paid in capital		3,624.2	3,580.2
Retained earnings		1,972.0	1,919.9
Accumulated other comprehensive loss		(23.1)	(24.5)
Total common stockholder’s equity		5,573.1	5,475.6
Total liabilities and equity		$ 18,469.9	$ 17,925.8

[1] Revenue subject for refund of $12.5 million and $15.1 million for 2018 and 2017, respectively, is included in other current liabilities.

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Capitalization
Common stock, shares authorized (in shares)	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	1,000,000	1,000,000

XML

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common stock	Additional Paid In Capital	Retained Earnings	AOCI Attributable to Parent
Beginning balance at Dec. 31, 2015	$ 5,167,000	$ 0	$ 3,323,800	$ 1,864,300	$ (21,100)
Balance (in shares) at Dec. 31, 2015		1,000,000
Increase (Decrease) in Stockholder's Equity
Net income	488,700			488,700
Other comprehensive income (loss)	300				300
Common dividends declared to parent	(411,700)			(411,700)
Contribution of capital by parent	111,300		111,300
Ending balance at Dec. 31, 2016	5,355,600	$ 0	3,435,100	1,941,300	(20,800)
Balance (in shares) at Dec. 31, 2016		1,000,000
Increase (Decrease) in Stockholder's Equity
Net income	490,100			490,100
Other comprehensive income (loss)	600				600
Common dividends declared to parent	(515,800)			(515,800)
Contribution of capital by parent	145,100		145,100
Adoption of ASU No. 2018-02 (a)				4,300	(4,300)
Ending balance at Dec. 31, 2017	$ 5,475,600	$ 0	3,580,200	1,919,900	(24,500)
Balance (in shares) at Dec. 31, 2017	1,000,000	1,000,000
Increase (Decrease) in Stockholder's Equity
Net income	$ 492,300			492,300
Other comprehensive income (loss)	1,400				1,400
Common dividends declared to parent	(440,200)			(440,200)
Contribution of capital by parent	44,000		44,000
Ending balance at Dec. 31, 2018	$ 5,573,100	$ 0	$ 3,624,200	$ 1,972,000	$ (23,100)
Balance (in shares) at Dec. 31, 2018	1,000,000	1,000,000

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

General — NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.

NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.

NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 3 for further information.

NSP-Minnesota’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions.

NSP-Minnesota has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates — NSP-Minnesota uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting — NSP-Minnesota accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

• Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — NSP-Minnesota accounts for income taxes using the asset and liability method, which requires deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. NSP-Minnesota uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset.

Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. NSP-Minnesota recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.

Recognition of changes in uncertain tax positions are reflected as a component of income tax.

NSP-Minnesota reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including NSP-Minnesota, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 7 for further information.

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred.

Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made.

For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

NSP-Minnesota records depreciation expense using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.6% for 2018, 3.6% for 2017, and 3.2% for 2016.

See Note 3 for further information.

AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset.

Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Minnesota also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

See Note 10 for further information.

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval.

For ratemaking purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each facility’s expected service life based on the triennial decommissioning studies filed with state commissions. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.

Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.

See Notes 8 and 10 for further information.

Benefit Plans and Other Postretirement Benefits — NSP-Minnesota maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

Revenue From Contracts With Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.

NSP-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees.

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

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

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

See Note 6 for further information.

Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of 3 months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

As of Dec. 31, 2018 and 2017, the allowance for bad debts was $23.5 million and $21.3 million, respectively.

Inventory— Inventory is recorded at average cost. As of Dec. 31, 2018, materials and supplies, fuel and natural gas inventory were $176.3 million, $88.5 million, and $34.6 million, respectively. As of Dec. 31, 2017, materials and supplies, fuel and natural gas inventory were $209.2 million, $94.5 million, and $34.0 million, respectively.

Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs.

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, NSP-Minnesota may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.

See Notes 8 and 9 for further information.

Derivative Instruments— NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.

Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.

Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

See Note 8 for further information.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 8 for further information.

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility rates.

Alternative Revenue — Certain rate rider mechanisms (including decoupling and CIP programs) qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, such as collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items.

Billing amounts are revised periodically for differences between the total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers in the period earned.

See Note 6 for further information.

Conservation Programs — Costs incurred for CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from when they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Emission Allowances — Emission allowances are recorded at cost plus broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

Nuclear Refueling Outage Costs —NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes refueling outage costs over the period between refueling outages consistent with rate recovery.

RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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Accounting Pronouncements

12 Months Ended

Dec. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Leases — In 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which requires balance sheet recognition of right-of-useassets and lease liabilities for most leases. Adoptionwill occur on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions of whether agreements existing before the adoption date contain leases, and whether existing leases are operating or capital/finance leases.

NSP-Minnesota expects to utilize other expedients offered by the new standard and Leases, Topic 842 (ASU No. 2018-11), including elections to not recognize short term leases on the consolidated balance sheet for certain classes of assets and to implement the standard on a prospective basis. NSP-Minnesota’s implementation of the new guidance is substantially complete, and is expected to result in the recognition of right-of-use assets and lease liabilities in the first quarter of 2019 for operating leases for the use of real estate, equipment and certain natural gas generating facilities operated under PPAs.

The implementation isnot expected to have a significant impact on NSP-Minnesota’s consolidatedfinancial statements, other than first-time recognition of these operating leases on the consolidated balance sheet.

Recently Adopted

Revenue Recognition— In 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. NSP-Minnesota implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance.

The implementation did not have a material impact on NSP-Minnesota’s consolidated financial statements, other than increased disclosures regarding revenues related to contracts with customers.

Classification and Measurement of Financial Instruments — In 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes.

NSP-Minnesota implemented the guidance on Jan. 1, 2018 and the adoption impacts were not material.

Presentation of Net Periodic Benefit Cost — In 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 portion of pension cost may be presented as a component of operating income. In addition, only the service cost portion of pension cost is eligible for capitalization.

As a result of regulatory accounting treatment, a similar amount of pension cost, including non-service components, will be recognized consistent with historical ratemaking and the impacts of adoption are limited to changes in classification of non-service costs in the consolidated statement of income.

NSP-Minnesota implemented the new guidance on Jan. 1, 2018. As a result, $14.8 million and $13.6 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other expense, net on the consolidated income statement for 2017 and 2016, respectively. NSP-Minnesota used benefit cost amounts disclosed for prior periods as the basis for retrospective application.

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Property Plant and Equipment Property Plant and Equipment

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

3. Property, Plant and Equipment

Major classes of property, plant and equipment:

(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
Property, plant and equipment
Electric plant	$	17,749.3		$	17,024.9
Natural gas plant	1,475.5			1,370.3
Common and other property	803.1			724.1
CWIP	615.1			530.1
Total property, plant and equipment	20,643.0			19,649.4
Less accumulated depreciation	(7,454.8		)	(7,018.2		)
Nuclear fuel	2,770.4			2,697.4
Less accumulated amortization	(2,416.9		)	(2,295.0		)
	$	13,541.7		$	13,033.6

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2018:

(Millions of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Percent Owned
Electric Generation:
Sherco Unit 3	$	604.2	$	415.0	$	1.0	59	%
Sherco Common Facilities	145.4		100.2		1.2		80
Other	4.8		3.4		—		59
Electric Transmission:
CapX2020 Transmission	959.6		72.7		1.9		51
Other	10.6		2.3		—		50
Total	$	1,724.6	$	593.6	$	4.1

NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2018

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.

Components of regulatory assets:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	28.1	$	424.3	$	28.5	$	403.7
Net AROs (a)	1, 10	Plant lives	—		323.4		—		193.1
Excess deferred taxes - TCJA	7	Various	—		153.3		—		133.1
Recoverable deferred taxes on AFUDC recorded in plant		Plant lives	—		117.6		—		119.0
Benson biomass PPA termination and asset purchase		Ten years	9.8		85.8		—		—
Contract valuation adjustments (b)	1, 8	Term of related contract	14.1		76.0		14.4		89.8
Laurentian biomass PPA termination		Five years	18.1		73.3		—		—
PI extended power update		Sixteen years	3.1		55.8		3.3		58.4
Purchased power contracts costs		Term of related contract	2.8		36.6		1.8		39.3
Conservation programs (c)	1	One to two years	34.5		21.1		40.4		25.9
Losses on reacquired debt		Term of related debt	2.1		15.5		2.2		17.6
Environmental remediation costs	1, 10	Pending future rate cases	1.3		14.3		—		24.6
Nuclear refueling outage costs	1	One to two years	36.3		13.5		49.3		19.7
Deferred purchased natural gas and electric energy costs		One to three years	5.6		12.6		13.5		13.3
Sales true-up and revenue decoupling		One to two years	38.3		6.7		37.3		12.4
State commission adjustments		Plant lives	—		3.4		—		3.5
Renewable resources and environmental initiatives		One to two years	39.2		0.4		45.9		0.4
Gas pipeline inspection and remediation costs		Less than one year	27.4		—		22.6		4.5
Other		Various	19.6		20.5		17.2		32.1
Total regulatory assets			$	280.3	$	1,454.1	$	276.4	$	1,190.4

^(a)  Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

^(b)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(c)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	153.7	$	1,465.1	$	—	$	1,516.1
Plant removal costs	1, 10	Plant lives	—		484.6		—		441.6
ITC deferrals (b)	1	Various	—		8.9		—		9.5
Deferred electric energy costs		Less than one year	22.8		—		11.3		—
DOE Settlement		Less than one year	13.0		—		12.8		—
Contract valuation adjustments (c)	1, 8	Less than one year	10.4		—		17.2		—
Renewable resources and environmental initiatives		Less than one year	8.8		—		19.4		—
Other		Various	53.7		26.1		22.7		11.3
Total regulatory liabilities (d)			$	262.4	$	1,984.7	$	83.4	$	1,978.5

^(a)  Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

^(b)  Includes impact of lower federal tax rate due to the TCJA.

^(c)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(d)  Revenue subject for refund of $12.5 million and $15.1 million for 2018 and 2017, respectively, is included in other current liabilities.

At Dec. 31, 2018 and 2017, approximately $149 million and $142 million, respectively, of NSP-Minnesota’s regulatory assets represented past expenditures not earning a return. Amounts primarily related to purchased natural gas and electric energy costs and certain expenditures associated with pension.

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

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

	Three Months Ended Dec. 31, 2018			Year Ended
(Amounts in Millions, Except Interest Rates)				2018			2017			2016
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	—			—			85			—
Average amount outstanding	18			17			25			16
Maximum amount outstanding	76			143			142			225
Weighted average interest rate, computed on a daily basis	2.23		%	1.96		%	1.14		%	0.69		%
Weighted average interest rate at period end	N/A			N/A			1.18			N/A

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

Commercial paper outstanding for NSP-Minnesota was as follows:

	Three Months Ended Dec. 31, 2018			Year Ended Dec. 31
(Amounts in Millions, Except Interest Rates)				2018			2017			2016
Borrowing limit	$	500		$	500		$	500		$	500
Amount outstanding at period end	150			150			20			85
Average amount outstanding	62			38			62			73
Maximum amount outstanding	198			198			237			353
Weighted average interest rate, computed on a daily basis	2.53		%	2.08		%	1.10		%	0.65		%
Weighted average interest rate at end of period	2.97			2.97			1.93			0.94

Letters of Credit — NSP-Minnesota uses letters of credit, typically with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2018 and 2017, there were $37 million and $24 million of letters of credit outstanding, respectively, under the credit facility. Amounts approximate their fair value.

Credit Facility — 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.

Features of NSP-Minnesota’s credit facility:

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions)		Additional Periods For Which a One-Year Extension May Be Requested (b)
2018		2017
48	%	48	%	$	100	2

^(a)  The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

^(b)  All extension requests are subject to majority bank group approval.

The credit facility has a cross-default provision that NSP-Minnesota will be in default on its borrowings under the facility if it or any of its subsidiaries whose total assets exceed 15% of NSP-Minnesota’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.

If NSP-Minnesota does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2018, NSP-Minnesota was in compliance with all financial covenants on its debt agreements.

NSP-Minnesota had the following committed credit facilities available as of Dec. 31, 2018 (in millions):

Credit Facility (a)		Drawn(b)		Available
$	500	$	187	$	313

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

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

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

Long-Term Borrowings and Other Financing Instruments

Generally, all property of NSP-Minnesota is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

Long term debt obligations for NSP-Minnesota as of Dec. 31:

(Millions of Dollars)	Maturity Range	Interest Rate Range 2018	Interest Rate Range 2017	2018			2017
NSP-Minnesota
Mortgage bonds	2020-2047	2.15% - 7.13%	2.15% - 7.13%	$	5,000		$	5,000
Unamortized discount				(21		)	(22		)
Unamortized debt issuance cost				(42		)	(45		)
Current maturities				—			—
Total				$	4,937		$	4,933

Maturities of long-term debt are as follows:

(Millions of Dollars)
2019	$	—
2020	300
2021	—
2022	300
2023	400

During 2018, NSP-Minnesota did not complete any new financings.

2017 financings:

	Amount	Financing Instrument	Interest Rate		Maturity Date
NSP-Minnesota	600 million	First mortgage bonds	3.60	%	Sept. 15, 2047

Deferred Financing Costs— Deferred financing costs of approximately $42 million and $45 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2018 and 2017, respectively.

Dividend Restrictions — NSP-Minnesota’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividend payments are solely to be paid from retained earnings.

NSP-Minnesota’s state regulatory commission imposes the most restrictive dividend limitations.

Requirements and actuals as of Dec. 31, 2018:

	Equity to Total Capitalization Ratio - Required Range				Equity to Total Capitalization Ratio - Actual
	Low		High		2018
NSP-Minnesota	47.1	%	57.5	%	52.3	%

	Unrestricted Retained Earnings			Total Capitalization			Limit on Total Capitalization
NSP-Minnesota	$	1.0	billion	$	10.7	billion	$	11.5	billion

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Revenues

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenues

Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following:

	Year Ended Dec. 31, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,308.4	$	308.8	$	27.2	$	1,644.4
C&I	2,052.1		239.3		0.2		2,291.6
Other	36.5		—		3.4		39.9
Total retail	3,397.0		548.1		30.8		3,975.9
Wholesale	189.2		—		—		189.2
Transmission	238.1		—		—		238.1
Interchange	473.7		—		—		473.7
Other	28.3		11.7		—		40.0
Total revenue from contracts with customers	4,326.3		559.8		30.8		4,916.9
Alternative revenue and other	181.7		23.3		—		205.0
Total revenues	$	4,508.0	$	583.1	$	30.8	$	5,121.9

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Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Federal Tax Reform— In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes NSP-Minnesota), generally beginning in 2018, include:

• Corporate federal tax rate reduction from 35% to 21%;

• Normalization of resulting plant-related excess deferred taxes;

• Elimination of the corporate alternative minimum tax;

• Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;

• Limitations on certain executive compensation deductions;

• Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80% of taxable income);

• Repeal of the section 199 manufacturing deduction; and,

• Reduced deductions for meals and entertainment as well as state and local lobbying.

Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements.

Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment.

Estimated impacts of the new tax law for NSP-Minnesota in December 2017 included:

• $1.1 billion ($1.5 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property;

• $133 million and $56 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and

• $19 million of total estimated income tax expense related to the federal tax reform implementation, and a $5 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.

Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.

Federal Tax Loss Carryback Claims — In 2012 - 2015, Xcel Energy 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, Xcel Energy recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012.

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

Tax Year(s)	Expiration
2009 - 2014	October 2019
2015	September 2019
2016	September 2020
2017	September 2021

In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. In 2017, Xcel Energy and the Office of Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2018, 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 the fourth quarter of 2018, the IRS began an audit of tax years 2014 - 2016, however 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 Dec. 31, 2018, NSP-Minnesota’s earliest open tax year subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the fourth quarter of 2018, the Minnesota audit of tax years 2010 - 2014 concluded with no material adjustments.

Unrecognized Tax 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)	Dec. 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	11.6	$	10.2
Unrecognized tax benefit — Temporary tax positions	5.3		7.9
Total unrecognized tax benefit	$	16.9	$	18.1

Changes in unrecognized tax benefits:

(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	18.1		$	60.8		$	55.4
Additions based on tax positions related to the current year	2.0			2.7			3.7
Reductions based on tax positions related to the current year	(0.3		)	(1.7		)	(0.2		)
Additions for tax positions of prior years	0.6			5.7			3.9
Reductions for tax positions of prior years	(1.1		)	(49.4		)	(2.0		)
Settlements with taxing authorities	(2.4		)	—			—
Balance at Dec. 31	$	16.9		$	18.1		$	60.8

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

(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(12.7	)	$	(12.8	)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $7.3 million and $5.7 million at Dec. 31, 2018 and Dec. 31, 2017, respectively.

As the IRS Appeals and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $13.7 million in the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)	2018			2017			2016
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.9	)	$	(2.0	)	$	(0.2	)
Interest (expense) income related to unrecognized tax benefits	(0.3		)	1.1			(1.8		)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(1.2	)	$	(0.9	)	$	(2.0	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2018, 2017, or 2016.

Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2018			2017
Federal NOL carryforward	$	—		$	631.6
Federal tax credit carryforwards	379.4			301.6
State NOL carryforwards	221.2			275.5
Valuation allowances for state NOL carryforwards	(0.8		)	(0.9		)
State tax credit carryforwards, net of federal detriment (a)	87.9			90.7
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(78.5		)	(82.2		)

^(a)  State tax credit carryforwards are net of federal detriment of $23.4 million and $24.1 million as of Dec. 31, 2018 and 2017, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $20.9 million and $21.8 million as of Dec. 31, 2018 and 2017, respectively.

Federal carryforward periods expire between 2021 and 2038 and state carryforward periods expire between 2019 and 2035.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:

	2018		2017 (a)		2016 (a)
Federal statutory rate	21.0	%	35.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	7.1		5.8		5.8
Increases (decreases) in tax from:
Wind PTCs recognized	(13.6	)	(11.4	)	(8.2	)
Regulatory differences - ARAM (b)	(9.1	)	(0.1	)	(0.1	)
Other tax credit recognized, net of federal income tax expense	(1.3	)	(1.0	)	(0.8	)
Regulatory differences - other utility plant items	0.3		(0.2	)	(0.2	)
Change in unrecognized tax benefits	0.1		(1.6	)	0.2
Tax reform	—		2.7		—
Other, net	0.7		(0.2	)	(0.2	)
Effective income tax rate	5.2	%	29.0	%	31.5	%

^(a)  Prior periods have been reclassified to conform to current year presentation.

^(b)  ARAM is a method to flow back excess deferred taxes to customers.

Components of income tax expense for years ended Dec. 31:

(Millions of Dollars)	2018			2017			2016
Current federal tax (benefit) expense	$	(16.8	)	$	29.6		$	19.3
Current state tax expense	5.2			14.7			9.4
Current change in unrecognized tax (benefit) expense	(1.1		)	(36.2		)	1.3
Deferred federal tax (benefit) expense	(2.4		)	121.6			142.3
Deferred state tax expense	42.1			46.7			53.8
Deferred change in unrecognized tax expense	1.6			24.9			0.1
Deferred ITCs	(1.4		)	(1.6		)	(1.7		)
Total income tax expense	$	27.2		$	199.7		$	224.5

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)	2018			2017			2016
Deferred tax expense (benefit) excluding items below	$	70.1		$	(1,176.4	)	$	225.1
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(28.2		)	1,369.9			(28.7		)
Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other	(0.6		)	(0.3		)	(0.2		)
Deferred tax expense	$	41.3		$	193.2		$	196.2

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2018			2017
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,257.6		$	2,253.2
Regulatory assets	263.1			222.7
Pension expense	64.7			54.2
Other	11.3			16.4
Total deferred tax liabilities	$	2,596.7		$	2,546.5
Deferred tax assets:
Regulatory liabilities	$	382.8		$	386.6
Tax credit carryforward	467.3			392.4
NOL carryforward	17.9			153.5
NOL and tax credit valuation allowance	(78.6		)	(82.2		)
Other employee benefits	38.6			37.3
Deferred ITCs	6.4			6.8
Rate refund	49.7			6.6
Other	30.2			33.2
Total deferred tax assets	$	914.3		$	934.2
Net deferred tax liability	$	1,682.4		$	1,612.3

XML

Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

• 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:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted 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. The investments in commingled funds may be redeemed for NAV with proper 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, however, may be delayed or discounted as a result of fund illiquidity.

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

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

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations 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 forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as 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.

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

Non-Derivative Fair Value Measurements

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other 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 over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.

Unrealized gains for the nuclear decommissioning fund were $450.1 million and $559.9 million as of Dec. 31, 2018 and 2017, respectively, and unrealized losses were $44.8 million and $7.4 million as of Dec. 31, 2018 and 2017, respectively.

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

	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 $52.5 million of rabbi trust assets and miscellaneous investments.

	Dec. 31, 2017
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	28.7	$	28.7	$	—	$	—	$	—	$	28.7
Commingled funds	701.3		222.8		—		—		659.1		$	881.9
Debt securities	437.7		—		441.6		—		—		$	441.6
Equity securities	423.1		791.1		—		—		—		$	791.1
Total	$	1,590.8	$	1,042.6	$	441.6	$	—	$	659.1	$	2,143.3

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $49.1 million of rabbi trust assets and miscellaneous investments.

For the years ended Dec. 31, 2018 and 2017, there were no Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2018:

	Final Contractual Maturity
(Millions of Dollars)	Due in 1Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	10.6	$	106.9	$	210.5	$	107.6	$	435.6

Rabbi Trusts

NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions.

Cost and fair value of assets held in rabbi trusts:

	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, 2017
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	0.8	$	0.8	$	—	$	—	$	0.8
Mutual funds	10.3		11.3		—		—		$	11.3
Total	$	11.1	$	12.1	$	—	$	—	$	12.1

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

Derivative 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.

As of Dec. 31, 2018, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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

As of Dec. 31, 2018, NSP-Minnesota had no vehicle fuel contracts designated as cash flow hedges. NSP-Minnesota 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 in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Immaterial amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2018 and 2017.

As of Dec. 31, 2018, there were no net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.

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

Gross notional amounts of commodity forwards, options and FTRs at Dec. 31:

(Amounts in Millions)(a) (b)	2018	2017
MWh of electricity	56.8	41.7
MMBtu of natural gas	42.7	23.8
Gallons of vehicle fuel	—	0.2

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

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. As of Dec. 31, 2018, six of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $35.9 million or 44% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.

Two of the 10 most significant counterparties, comprising $14.4 million or 18% 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. One of the 10 most significant counterparties, comprising $1.3 million or 2% of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. One of the 10 most significant counterparties, comprising $11.8 million or 14% of this credit exposure, had credit quality less than investment grade based on rating from internal analysis. Seven of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)	2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(20.9	)	$	(18.2	)	$	(19.1	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			0.1			—
After-tax net realized losses on derivative transactions reclassified into earnings	0.7			0.9			0.9
Adoption of ASU. 2018-02 (a)	—			(3.7		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(20.2	)	$	(20.9	)	$	(18.2	)

^(a)  In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

Impact of derivative activity:

	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2018
Other derivative instruments
Electric commodity	$	—	$	(5.5	)
Natural gas commodity	—		1.8
Total	$	—	$	(3.7	)
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Vehicle fuel and other commodity	$	0.1	$	—
Total	$	0.1	$	—
Other derivative instruments
Electric commodity	$	—	$	9.3
Natural gas commodity	—		(1.9		)
Total	$	—	$	7.4
Year Ended Dec. 31, 2016
Other derivative instruments
Electric commodity	—		14.4
Natural gas commodity	—		(1.2		)
Total	$	—	$	13.2

	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)
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1.1		(a)	$	—			$	—
Vehicle fuel and other commodity	(0.1		)	(b)	—				—
Total	$	1.0			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	10.9		(c)
Electric commodity	—				3.3			(d)	—
Natural gas commodity	—				(1.9		)	(e)	(1.3		)	(e)
Total	$	—			$	1.4			$	9.6
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Interest rate	$	1.5		(a)	$	—			$	—
Total	$	1.5			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	9.4		(c)
Electric commodity	—				(13.8		)	(d)	—
Natural gas commodity	—				1.0			(e)	(1.2		)	(e)
Total	$	—			$	(12.8	)		$	8.2
Year Ended Dec. 31, 2016
Derivatives designated as cash flow hedges
Interest rate	$	1.4		(a)	$	—			$	—
Vehicle fuel and other commodity	0.1			(b)	—				—
Total	$	1.5			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	2.8		(c)
Electric commodity	—				(6.1		)	(d)	—
Natural gas commodity	—				4.0			(e)	(2.2		)	(e)
Total	$	—			$	(2.1	)		$	0.6

^(a)  Amounts are recorded to interest charges.

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

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

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

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

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2018, 2017 and 2016.

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 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 if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2018 and 2017, there were no derivative instruments in a liability position with such underlying contract provisions.

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

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2018 and 2017:

	Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total		Netting (a)					Fair Value						Fair Value Total		Netting (a)
(Millions of Dollars)	Level 1		Level 2		Level 3							Total		Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	—	$	—	$	—	$	—		$	—	$	—	$	0.1	$	—	$	0.1	$	—		$	0.1
Other derivative instruments:
Commodity trading	1.1		27.1		2.2		30.4		(16.0		)	14.4		1.7		17.1		0.1		18.9		(11.7		)	7.2
Electric commodity	—		—		10.5		10.5		(0.1		)	10.4		—		—		17.6		17.6		(0.4		)	17.2
Natural gas commodity	—		1.0		—		1.0		—			1.0		—		0.1		—		0.1		—			0.1
Total current derivative assets	$	1.1	$	28.1	$	12.7	$	41.9	$	(16.1	)	25.8		$	1.7	$	17.3	$	17.7	$	36.7	$	(12.1	)	24.6
PPAs (b)												—													0.6
Current derivative instruments												$	25.8												$	25.2
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	25.3	$	5.0	$	30.3	$	(13.4	)	$	16.9	$	—	$	29.1	$	5.4	$	34.5	$	(6.5	)	$	28.0
Total noncurrent derivative assets	$	—	$	25.3	$	5.0	$	30.3	$	(13.4	)	16.9		$	—	$	29.1	$	5.4	$	34.5	$	(6.5	)	28.0
PPAs (b)												0.1													0.1
Noncurrent derivative instruments												$	17.0												$	28.1

	Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total		Netting (a)					Fair Value						Fair Value Total		Netting (a)
(Millions of Dollars)	Level 1		Level 2		Level 3							Total		Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1.4	$	23.9	$	1.7	$	27.0	$	(24.5	)	$	2.5	$	1.7	$	13.9	$	—	$	15.6	$	(12.0	)	$	3.6
Electric commodity	—		—		0.1		0.1		(0.1		)	—		—		—		0.4		0.4		(0.4		)	—
Total current derivative liabilities	$	1.4	$	23.9	$	1.8	$	27.1	$	(24.6	)	2.5		$	1.7	$	13.9	$	0.4	$	16.0	$	(12.4	)	3.6
PPAs (b)												14.0													14.1
Current derivative instruments												$	16.5												$	17.7
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	0.1	$	16.0	$	1.6	$	17.7	$	17.9		$	35.6	$	—	$	22.2	$	—	$	22.2	$	(9.4	)	$	12.8
Total noncurrent derivative liabilities	$	0.1	$	16.0	$	1.6	$	17.7	$	17.9		35.6		$	—	$	22.2	$	—	$	22.2	$	(9.4	)	12.8
PPAs (b)												76.6													89.9
Noncurrent derivative instruments												$	112.2												$	102.7

^(a)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2018 and 2017. At Dec. 31, 2018 and 2017, derivative assets and liabilities include $31.5 million and $0 million of obligations to return cash collateral, respectively. At Dec. 31, 2018 and 2017, derivative assets and liabilities include the rights to reclaim cash collateral of $8.7 million and $3.1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  During 2006, 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.

Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2018, 2017 and 2016:

	Year Ended Dec. 31
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	22.6		$	15.3		$	13.0
Purchases	26.4			40.6			28.0
Settlements	(17.2		)	(41.7		)	(47.2		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(1.5		)	5.5			—
Net (losses) gains recognized as regulatory assets and liabilities	(16.0		)	2.9			21.5
Balance at Dec. 31	$	14.3		$	22.6		$	15.3

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

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended 2016 - 2018.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

	2018				2017
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,937.2	$	5,230.9	$	4,933.0	$	5,601.9

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

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Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

Xcel Energy, which includes NSP-Minnesota, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service and average pay. Xcel Energy’s and NSP-Minnesota’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2018 and 2017 were $33 million and $37 million, respectively, of which $4 million and $5 million were attributable to NSP-Minnesota. In 2018 and 2017, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million and $5 million, respectively, of which $1 million was attributable to NSP-Minnesota in both years.

In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to NSP-Minnesota will be supplemented by NSP-Minnesota’s consolidated operating cash flows.

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees.

• NSP-Minnesota discontinued subsidizing health care benefits for non-bargaining employees retiring after 1998 and for bargaining employees who retired after 1999.

Xcel Energy and NSP-Minnesota base the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios.

For pension assets, Xcel Energy and NSP-Minnesota consider the historical returns achieved by their asset portfolio over the past 20 years or longer period, as well as the long-term projected return levels. Xcel Energy and NSP-Minnesota continually review their pension assumptions.

Pension cost determination assumes a forecasted mix of investment types over the long-term.

• Investment returns in 2018 were below the assumed level of 7.10%;

• Investment returns in 2017 were above the assumed level of 7.10%;

• Investment returns in 2016 were below the assumed level of 7.10%; and

• In 2019, NSP-Minnesota’s expected investment-return assumption is 7.10%.

Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s and NSP-Minnesota’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.

There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.

State agencies also have issued guidelines to the funding of postretirement benefit costs.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

The following presents, for each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value:

	Dec. 31, 2018 (a)												Dec. 31, 2017 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV			Total			Level 1			Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	31.8	$	—	$	—	$	—		$	31.8		$	53.4		$	—	$	—	$	—	$	53.4
Commingled funds:	241.0		—		—		271.2			512.2			285.2			—		—		302.4		587.6
Debt securities:	—		143.7		—		—			143.7			—			159.0		—		—		159.0
Equity securities:	29.3		—		—		—			29.3			32.1			—		—		—		32.1
Other	0.5		1.3		—		(8.2		)	(6.4		)	(8.7		)	1.0		—		0.1		$	(7.6	)
Total	$	302.6	$	145.0	$	—	$	263.0		$	710.6		$	362.0		$	160.0	$	—	$	302.5	$	824.5

^(a)  See Note 8 for further information on fair value measurement inputs and methods.

The following presents, for each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value:

	Dec. 31, 2018 (a)										Dec. 31, 2017 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	0.1	$	—	$	—	$	—	$	0.1	$	0.4	$	—	$	—	$	—	$	0.4
Insurance contracts	—		0.3		—		—		0.3		—		0.7		—		—		0.7
Commingled funds	0.8		—		—		0.2		1.0		2.1		—		—		—		2.1
Debt securities	—		1.0		—		—		1.0		—		2.8		—		—		2.8
Equity securities	—		—		—		—		—		0.5		—		—		—		0.5
Total	$	0.9	$	1.3	$	—	$	0.2	$	2.4	$	3.0	$	3.5	$	—	$	—	$	6.5

^(a)  See Note 8 for further information on fair value measurement inputs and methods.

No assets transferred in or out of Level 3 for 2018 or 2017.

Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for NSP-Minnesota are as follows:

	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,035.1		$	1,036.5		$	88.8		$	86.7
Service cost	28.0			27.8			0.2			0.1
Interest cost	35.2			40.7			3.1			3.4
Plan amendments	—			(4.4		)	—			—
Actuarial (gain) loss	(50.8		)	64.1			(9.0		)	5.9
Plan participants’ contributions	—			—			0.4			0.4
Benefit payments (a)	(140.5		)	(129.6		)	(7.5		)	(7.7		)
Obligation at Dec. 31	$	907.0		$	1,035.1		$	76.0		$	88.8
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	824.5		$	783.2		$	6.5		$	3.7
Actual return on plan assets	(36.5		)	110.1			—			—
Employer contributions	63.1			60.7			3.0			10.1
Plan participants’ contributions	—			—			0.4			0.4
Benefit payments	(140.5		)	(129.5		)	(7.5		)	(7.7		)
Fair value of plan assets at Dec. 31	$	710.6		$	824.5		$	2.4		$	6.5
Funded status of plans at Dec. 31	$	(196.4	)	$	(210.6	)	$	(73.6	)	$	(82.3	)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Current assets (liabilities)	$	—		$	—		$	(4.8	)	$	(1.3	)
Noncurrent assets (liabilities)	(196.4		)	(210.6		)	(68.8		)	(81.0		)
Net amounts recognized	$	(196.4	)	$	(210.6	)	$	(73.6	)	$	(82.3	)

^(a)  Includes approximately $105 million of lump-sum benefit payments used in the determination of a settlement charge.

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.31	%	3.63	%	4.32	%	3.62	%
Expected average long-term increase in compensation level	3.75	%	3.75	%	N/A		N/A
Mortality table	RP-2014		RP-2014		RP-2014		RP-2014
Health care costs trend rate — initial: Pre-65	N/A		N/A		6.50	%	7.00	%
Health care costs trend rate — initial: Post-65	N/A		N/A		5.30	%	5.50	%
Ultimate trend assumption — initial: Pre-65	N/A		N/A		4.50	%	4.50	%
Ultimate trend assumption — initial: Post-65	N/A		N/A		4.50	%	4.50	%
Years until ultimate trend is reached	N/A		N/A		4		5

The accumulated benefit obligation for the pension plan was $845 million and $969 million as of Dec. 31, 2018 and 2017, respectively.

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit) other than the service cost component is included in other income in the consolidated statement of income.

Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:

	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2018			2017			2016			2018			2017			2016
Service cost	$	28.0		$	27.8		$	28.3		$	0.2		$	0.1		$	0.1
Interest cost	35.2			40.7			45.4			3.1			3.4			3.9
Expected return on plan assets	(58.2		)	(60.1		)	(60.9		)	(0.4		)	(0.2		)	(0.2		)
Amortization of prior service cost	(0.1		)	1.1			0.9			(3.0		)	(3.0		)	(3.0		)
Amortization of net loss	38.5			39.6			36.8			2.4			2.0			1.6
Settlement charge (a)	48.8			48.2			—			—			—			—
Net periodic pension cost	92.2			97.3			50.5			2.3			2.3			2.4
Costs not recognized due to effects of regulation	(66.0		)	(72.2		)	(20.9		)	—			—			—
Net benefit cost recognized for financial reporting	$	26.2		$	25.1		$	29.6		$	2.3		$	2.3		$	2.4
Significant Assumptions Used to Measure Costs:
Discount rate	3.63		%	4.13		%	4.66		%	3.62		%	4.13		%	4.65		%
Expected average long-term increase in compensation level	3.75			3.75			4.00			—			—			—
Expected average long-term rate of return on assets	7.10			7.10			7.10			5.30			5.80			5.80

^(a)  A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of $48.8 million in 2018 and $48.2 million in 2017, which was not recognized due to the effects of regulation.

	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	502.0		$	545.3		$	34.3		$	45.3
Prior service (credit) cost	(1.2		)	(1.3		)	(12.4		)	(15.4		)
Total	$	500.8		$	544.0		$	21.9		$	29.9
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	35.5		$	37.7		$	—		$	—
Noncurrent regulatory assets	465.3			506.3			20.5			28.0
Deferred income taxes	—			—			0.4			0.5
Net-of-tax accumulated other comprehensive income	—			—			1.0			1.4
Total	$	500.8		$	544.0		$	21.9		$	29.9
Measurement date	Dec. 31, 2018			Dec. 31, 2017			Dec. 31, 2018			Dec. 31, 2017

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2016 - 2019 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

• $150 million in January 2019, of which $47 million is attributable to NSP-Minnesota;

• $150 million in 2018, of which $63 million was attributable to NSP-Minnesota;

• $162 million in 2017, of which $61 million was attributable to NSP-Minnesota; and,

• $125 million in 2016, of which $49 million was attributable to NSP-Minnesota.

The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Voluntary postretirement funding contributions:

• $11 million in January 2019, of which $7 million is attributable to NSP-Minnesota;

• $11 million in 2018, of which $3 million, was attributable to NSP-Minnesota;

• $20 million in 2017, of which $10 million was attributable to NSP-Minnesota; and,

• $18 million in 2016, of which $9 million was attributable to NSP-Minnesota.

Target asset allocations:

	Pension Benefits				Postretirement Benefits
	2018		2017		2018		2017
Domestic and international equity securities	37	%	38	%	18	%	24	%
Long-duration fixed income and interest rate swap securities	28		23		—		—
Short-to-intermediate fixed income securities	18		21		70		60
Alternative investments	15		16		8		9
Cash	2		2		4		7
Total	100	%	100	%	100	%	100	%

Plan Amendments —Xcel Energy, which includes NSP-Minnesota, amended the Xcel Energy Pension Plan in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2016, the Xcel Energy Pension Plan was amended to change the discount rate basis for lump-sum conversion to annuity participants and annuity conversion to lump-sum participants.

In 2018 and 2017, there were no plan amendments made which affected the benefit obligation.

Projected Benefit Payments

NSP-Minnesota’s projected benefit payments:

(Millions of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2019	$	93.4	$	7.2	$	—	$	7.2
2020	81.2		7.0		—		7.0
2021	80.1		6.7		—		6.7
2022	79.0		6.3		—		6.3
2023	77.2		6.0		—		6.0
2024-2027	342.3		26.0		—		26.0

Defined Contribution Plans

Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for NSP-Minnesota was approximately $12 million in 2018, $12 million in 2017 and $12 million in 2016.

Multiemployer Plans

NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

al

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 complex judgments about future events. Management maintains accruals for 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 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.

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 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 filed comments agreeing 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.

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 a New England Transmission Owners base ROE order that addressed the D.C. Circuit’s actions on Opinion No. 531. Under a new proposed two step ROE approach, the FERC has 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, CAPM, and Expected Earnings models. The FERC proposes that if necessary, it would then set a new ROE by averaging the results of these models plus a Risk Premium model.

With respect to the MISO TOs, the FERC subsequently made preliminary determinations in a November 2018 order that the MISO 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 compliant period, compared to the previously ordered base ROE of 10.32%. A procedural schedule has been set for the first half of 2019, with the FERC expected to act no earlier than the second half of 2019. NSP-Minnesota has recognized a current refund liability consistent with its best estimate of the final ROE.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for NSP-Minnesota, which are normally recovered through the regulated rate process.

Site Remediation — Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota’s predecessors or other parties have caused environmental contamination.

Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to have sent wastes to that site.

MGP, Landfill or Disposal Sites — NSP-Minnesota is currently investigating or remediating six MGP, landfill or other disposal sites sites across its service territories, and these activities will continue through at least 2019. NSP-Minnesota accrued $6 million as of Dec. 31, 2018, and $19 million as of Dec. 31, 2017 for these sites. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting some portion of costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation —NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste.In 2015, the EPA published the CCR Rule. Litigation was brought challenging the rule in the D.C. Circuit. 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 additional groundwater sampling and will evaluate 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. In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. Litigation is ongoing regarding the deadline for closing or retrofitting these impoundments. The decision will require NSP-Minnesota to expedite closure plans for one impoundment in Minnesota (see ARO removal costs below) and will require the construction of a new impoundment, which is estimated to cost $6 million.

Federal CWA WOTUS Rule —In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. The Rule has been subject to significant litigation and is currently stayed in a portion of the country. NSP-Minnesota cannot estimate potential impacts until the legal and administrative processes are finalized, but expects costs will be recoverable through regulatory mechanisms.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, NSP-Minnesota estimates that ELG compliance will cost approximately $10 million to complete. The EPA, however, is conducting a rulemaking process to potentially revise the effluent limitations and pretreatment standards, which may impact compliance costs. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms.

FederalCWASection 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. NSP-Minnesota estimates the likely cost for complying with impingement and entrainment requirements is approximately $39 million, to be incurred between 2019 and 2028. NSP-Minnesota believes six plants could be required by state regulators to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to $194 million. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms.

AROs — AROs have been recorded for NSP-Minnesota’s assets. For nuclear assets, the ARO is associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello and PI.

Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was 2.1 billion for 2018 and 2017.

NSP-Minnesota’s AROs were as follows:

	Dec. 31, 2018
(Millions of Dollars)	Jan. 1, 2018		Amounts Settled (a)			Accretion		Cash Flow Revisions (b)			Dec. 31, 2018(c)
Electric
Nuclear	$	1,873.6	$	—		$	94.7	$	—		$	1,968.3
Wind	94.1		—			4.3		6.5			104.9
Steam and other production	64.0		(6.6		)	2.1		(10.3		)	49.2
Distribution	5.8		—			0.2		8.5			14.5
Miscellaneous	1.9		—			—		(0.1		)	1.8
Natural gas
Transmission and distribution	43.6		—			1.8		(7.2		)	38.2
Miscellaneous	0.2		—			—		—			0.2
Common
Miscellaneous	0.7		—			0.1		—			0.8
Total liability	$	2,083.9	$	(6.6	)	$	103.2	$	(2.6	)	$	2,177.9

^(a)  Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

^(b)  In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.

^(c)  There were no ARO amounts incurred in 2018.

	Dec. 31, 2017
(Millions of Dollars)	Jan. 1, 2017		Amounts Settled (a)			Accretion		Cash Flow Revisions (b)			Dec. 31, 2017 (c)
Electric
Nuclear	$	2,249.3	$	—		$	113.8	$	(489.5	)	$	1,873.6
Wind	90.1		—			4.0		—			94.1
Steam and other production	68.5		(4.9		)	2.4		(2.0		)	64.0
Distribution	5.6		—			0.2		—			5.8
Miscellaneous	1.8		—			0.1		—			1.9
Natural gas
Transmission and distribution	35.8		—			1.5		6.3			43.6
Miscellaneous	0.2		—			—		—			0.2
Common
Miscellaneous	1.3		(0.6		)	—		—			0.7
Total liability	$	2,452.6	$	(5.5	)	$	122.0	$	(485.2	)	$	2,083.9

^(a)  Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

^(b)  In 2017, AROs were revised for changes in timing and estimates of cash flows. Nuclear AROs decreased due to updated assumptions in the nuclear triennial filing.

^(c)  There were no ARO amounts incurred in 2017.

Indeterminate AROs —Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2018. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — NSP-Minnesota records a regulatory liability for the plant removal costs that are recovered currently in rates. These removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2018 and 2017 were $485 million and $442 million.

Nuclear Related

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $14.1 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450.0 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.6 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear incident. NSP-Minnesota is subject to assessments of up to $137.6 million per reactor-incident for each of its three licensed reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $20.5 million per reactor-incident during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was effective November 2018.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of approximately $18.0 million for business interruption insurance and $39.0 million for property damage insurance if losses exceed accumulated reserve funds.

Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.

NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 44 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life.

Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.

Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.

The obligation for decommissioning is expected to be funded 100% by the external decommissioning trust fund. This cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%. Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.

NSP-Minnesota has accumulated $2.1 billion of assets held in external decommissioning trusts in 2018. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements (ARO).

	Regulatory Basis
(Millions of Dollars)	2018			2017
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)	$	3,012.3		$	3,012.3
Effect of escalating costs	538.9			395.7
Estimated decommissioning cost obligation (in current dollars)	3,551.2			3,408.0
Effect of escalating costs to payment date	7,654.3			7,797.5
Estimated future decommissioning costs (undiscounted)	11,205.5			11,205.5
Effect of discounting obligation (using average risk-free interest rate of 3.33% and 2.80% for 2018 and 2017, respectively)	(6,911.5		)	(6,398.1		)
Discounted decommissioning cost obligation	$	4,294.0		$	4,807.4
Assets held in external decommissioning trust	$	2,054.7		$	2,143.3
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation	2,239.3			2,664.1

Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.

Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:

(Millions of Dollars)	2018			2017
Discounted decommissioning cost obligation - regulated basis	$	4,294.0		$	4,807.4
Differences in discount rate and market risk premium	(1,446.4		)	(1,402.8		)
O&M costs not included for GAAP	(879.3		)	(1,041.5		)
ARO differences between 2017 and 2014 cost studies	—			(489.5		)
Nuclear production decommissioning ARO - GAAP	$	1,968.3		$	1,873.6

Decommissioning expenses recognized as a result of regulation:

(Millions of Dollars)	2018		2017		2016
Annual decommissioning recorded as depreciation expense: (a) (b)	$	20.4	$	20.4	$	20.4

^(a)  Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

^(b)  Decommissioning expenses in 2018, 2017 and 2016 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14.0 million.

The 2014 nuclear decommissioning filing approved in 2015 has been used for the regulatory presentation for 2018, 2017 and 2016. The most recent triennial filing was submitted in December 2017 and was approved by the MPUC. It became effective on Jan. 1, 2019 and continued the accrual previously approved in the MPUC order, dated October 2015 from the 2014 filing. The 2020 accrual will be set subsequent to a compliance filing that is expected to be submitted in July 2019.

Leases — NSP-Minnesota leases a variety of equipment and facilities. These leases, primarily for office space, railcars, generating facilities, natural gas pipeline transportation, vehicles, aircraft and power-operated equipment, are accounted for as operating leases.

Total expenses (including capacity payments) under operating lease obligations for NSP-Minnesota and the corresponding capacity payments for PPAs accounted for as operating leases for the year ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Total expense	$	76.2	$	76.9	$	79.1
Capacity payments	62.5		62.7		63.4

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases.

Future commitments under operating leases:

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

^(a)  Amounts do not include PPAs accounted for as executory contracts.

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

Non-Lease PPAs— NSP-Minnesota has entered into PPAs with other utilities and energy suppliers with expiration dates through 2039 for purchased power to meet system load and energy requirements, meet operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments.

Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $52.7 million, $84.1 million and $89.8 million in 2018, 2017 and 2016, respectively.

At Dec. 31, 2018, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)	Capacity		Energy (a)
2019	$	54.0	$	98.7
2020	54.6		109.4
2021	62.2		157.4
2022	61.3		172.9
2023	62.7		176.9
Thereafter	109.5		328.1
Total (b)	$	404.3	$	1,043.4

^(a)  Excludes contingent energy payments for renewable energy PPAs.

^(b)  Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Fuel Contracts — NSP-Minnesota has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2019 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases for these contracts as of Dec. 31, 2018:

(Millions of Dollars)	Coal		Nuclear fuel		Natural gas supply		Natural gas storage and transportation
2019	$	194.7	$	127.1	$	43.6	$	107.4
2020	87.4		50.9		1.4		97.5
2021	52.0		99.0		1.4		95.6
2022	34.7		78.5		0.8		92.6
2023	35.1		99.4		—		82.8
Thereafter	3.5		337.1		—		320.7
Total (a)	$	407.4	$	792.0	$	47.2	$	796.6

^(a)  Includes amounts allocated to NSP-Wisconsin through intercompany charges.

VIEs — Under certain PPAs, NSP-Minnesota purchases power from IPPs for which NSP-Minnesota is required to reimburse fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. NSP-Minnesota has determined that certain IPPs are VIEs. NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

NSP-Minnesota evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities.

NSP-Minnesota 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. NSP-Minnesota had approximately 1002 MW and 1,069 MW of capacity under long-term PPAs at Dec. 31, 2018 and 2017, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2027.

Other

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

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

(Millions of Dollars)	Guarantor	Guarantee Amount		Current Exposure		Triggering Event
Guarantee of residual value of assets under the Bank of Tokyo-Mitsubishi Capital Corporation Equipment Leasing Agreement	NSP-Minnesota	$	4.8	$	—	(a)

^(a)  Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term in 2019.

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Other Comprehensive Income

12 Months Ended

Dec. 31, 2018

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

11.    Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2018 and 2017:

	2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(20.9	)		$	0.1		$	(3.7	)		$	(24.5	)
Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0, and $0.3 respectively)	—				(0.1		)	0.6				0.5
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.3, $0, and $0, respectively) (a)	0.7			(a)	—			—				0.7
Amortization of net actuarial loss (net of taxes of $0, $0, and $0.1, respectively)	—				—			0.2			(b)	0.2
Net current period other comprehensive income (loss)	0.7				(0.1		)	0.8				1.4
Accumulated other comprehensive loss at Dec. 31	$	(20.2	)		$	—		$	(2.9	)		$	(23.1	)

	2017
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(18.2	)		$	0.1	$	(2.7	)		$	(20.8	)
Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0, and $0.1, respectively)	0.1				—		(0.5		)		(0.4		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.6, $0, and $0, respectively)	0.9			(a)	—		—				0.9
Amortization of net actuarial loss (net of taxes of $0, $0, and $0.1, respectively)	—				—		0.1			(b)	0.1
Net current period other comprehensive income (loss)	1.0				—		(0.4		)		0.6
Adoption of ASU No. 2018-02 (c)	(3.7		)		—		(0.6		)		(4.3		)
Accumulated other comprehensive (loss) income at Dec. 31	$	(20.9	)		$	0.1	$	(3.7	)		$	(24.5	)

^(a)  Included in interest charges.

^(b)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

^(c)  In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

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Segments and Related Information

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Segment Information

Segments and Related Information

Operating results from 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 — 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 costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

NSP-Minnesota’s segment information is as follows:

(Millions of Dollars)	2018			2017			2016
Regulated Electric
Operating revenues (a)	$	4,508.0		$	4,541.8		$	4,404.6
Intersegment revenues	0.8			0.6			0.6
Total operating revenue	$	4,508.8		$	4,542.4		$	4,405.2
Depreciation and amortization	697.8			661.3			554.3
Interest charges and financing costs	199.5			199.8			200.8
Income tax expense	16.4			179.9			215.5
Net income	450.4			462.5			465.4
Regulated Natural Gas
Operating revenues (a)	$	583.1		$	531.9		$	467.4
Intersegment revenues	0.5			0.5			0.5
Total operating revenue	$	583.6		$	532.4		$	467.9
Depreciation and amortization	43.3			38.7			41.8
Interest charges and financing costs	14.8			13.5			13.2
Income tax expense	10.2			10.0			12.0
Net income	34.2			28.4			18.3
All Other
Operating revenues (a)	$	30.8		$	28.3		$	28.3
Depreciation and amortization	0.5			0.6			0.6
Interest charges and financing costs	—			—			—
Income tax expense	0.6			9.8			(3.0		)
Net income	7.7			(0.8		)	5.0
Consolidated Total
Total operating revenue	$	5,123.2		$	5,103.1		$	4,901.4
Reconciling eliminations	(1.3		)	(1.1		)	(1.1		)
Consolidated total revenue	$	5,121.9		$	5,102.0		$	4,900.3
Depreciation and amortization	741.6			700.6			596.7
Interest charges and financing costs	214.3			213.3			214.0
Income tax expense	27.2			199.7			224.5
Net income	492.3			490.1			488.7

^(a)  Operating revenues include $473.7 million, $490.2 million, and $475.5 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 13 for further information.

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Related Party Transactions

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Minnesota uses the services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 5 for further information.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.

Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Operating revenues:
Electric	$	473.7	$	490.2	$	475.5
Operating expenses:
Purchased power	61.1		66.8		63.0
Transmission expense	96.8		110.5		107.5
Other operating expenses — paid to Xcel Energy Services Inc.	534.8		539.4		513.0
Interest expense	0.3		—		—

Accounts receivable and payable with affiliates at Dec. 31 were:

	2018				2017
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Wisconsin	$	11.0	$	—	$	17.8	$	—
PSCo	—		17.9		—		7.7
SPS	—		4.7		—		1.0
Other subsidiaries of Xcel Energy Inc.	—		87.1		30.7		71.4
	$	11.0	$	109.7	$	48.5	$	80.1

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Millions of Dollars)	March 31, 2018		June 30, 2018		Sept. 30, 2018		Dec. 31, 2018
Operating revenues	$	1,310.8	$	1,187.7	$	1,351.8	$	1,271.6
Operating income	171.4		150.1		259.5		135.5
Net income	111.7		92.4		201.2		87.0

	Quarter Ended
(Millions of Dollars)	March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
Operating revenues	$	1,307.1	$	1,164.9	$	1,355.8	$	1,274.2
Operating income (a)	182.5		173.1		339.7		187.4
Net income	94.2		87.7		229.0		79.3

^(a)  In 2018, NSP-Minnesota implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.

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Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2018

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II, Valuation and Qualifying Accounts

NSP-MINNESOTA AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31

	Allowance for bad debts
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	21.3		$	20.0		$	20.8
Additions Charged to Costs and Expenses	16.2			15.7			15.0
Additions Charged to Other Accounts (a)	4.1			3.8			4.2
Deductions from Reserves (b)	(18.1		)	(18.2		)	(20.0		)
Balance at Dec. 31	$	23.5		$	21.3		$	20.0

^(a)  Recovery of amounts previously written off.

^(b)  Deductions relate primarily to bad debt write-offs.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Business and System of Accounts

General — NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.

NSP-Minnesota’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions.

Principles of Consolidation

NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.

NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 3 for further information.

Subsequent Events

NSP-Minnesota has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates

Use of Estimates — NSP-Minnesota uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting

Regulatory Accounting — NSP-Minnesota accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

• Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes

Income Taxes — NSP-Minnesota accounts for income taxes using the asset and liability method, which requires deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. NSP-Minnesota uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset.

Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. NSP-Minnesota recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.

Recognition of changes in uncertain tax positions are reflected as a component of income tax.

NSP-Minnesota reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including NSP-Minnesota, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 7 for further information.

Property, Plant and Equipment and Depreciation

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred.

Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made.

For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

NSP-Minnesota records depreciation expense using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.6% for 2018, 3.6% for 2017, and 3.2% for 2016.

See Note 3 for further information.

Asset Retirement Obligations

AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset.

Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Minnesota also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

See Note 10 for further information.

Nuclear Decommissioning

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval.

For ratemaking purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each facility’s expected service life based on the triennial decommissioning studies filed with state commissions. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.

Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.

See Notes 8 and 10 for further information.

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits — NSP-Minnesota maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

Environmental Costs

Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

Revenue From Contracts With Customers

Revenue From Contracts With Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.

NSP-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees.

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

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

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

See Note 6 for further information.

Cash and Cash Equivalents

Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of 3 months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

As of Dec. 31, 2018 and 2017, the allowance for bad debts was $23.5 million and $21.3 million, respectively.

Inventory

Inventory— Inventory is recorded at average cost. As of Dec. 31, 2018, materials and supplies, fuel and natural gas inventory were $176.3 million, $88.5 million, and $34.6 million, respectively. As of Dec. 31, 2017, materials and supplies, fuel and natural gas inventory were $209.2 million, $94.5 million, and $34.0 million, respectively.

Fair Value Measurements

Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs.

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, NSP-Minnesota may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.

See Notes 8 and 9 for further information.

Derivative Instruments

Derivative Instruments— NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.

Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.

Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

See Note 8 for further information.

Commodity Trading Operations

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 8 for further information.

AFUDC

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility rates.

Alternative Revenue Programs

Alternative Revenue — Certain rate rider mechanisms (including decoupling and CIP programs) qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, such as collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items.

Billing amounts are revised periodically for differences between the total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers in the period earned.

See Note 6 for further information.

Conservation Programs — Costs incurred for CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from when they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Emission Allowances

Emission Allowances — Emission allowances are recorded at cost plus broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

Nuclear Refueling Outage Costs

Nuclear Refueling Outage Costs —NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes refueling outage costs over the period between refueling outages consistent with rate recovery.

Renewable Energy Credits

RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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Property Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Public Utility Property, Plant, and Equipment

3. Property, Plant and Equipment

Major classes of property, plant and equipment:

(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
Property, plant and equipment
Electric plant	$	17,749.3		$	17,024.9
Natural gas plant	1,475.5			1,370.3
Common and other property	803.1			724.1
CWIP	615.1			530.1
Total property, plant and equipment	20,643.0			19,649.4
Less accumulated depreciation	(7,454.8		)	(7,018.2		)
Nuclear fuel	2,770.4			2,697.4
Less accumulated amortization	(2,416.9		)	(2,295.0		)
	$	13,541.7		$	13,033.6

Schedule of Jointly Owned Utility Plants

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2018:

(Millions of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Percent Owned
Electric Generation:
Sherco Unit 3	$	604.2	$	415.0	$	1.0	59	%
Sherco Common Facilities	145.4		100.2		1.2		80
Other	4.8		3.4		—		59
Electric Transmission:
CapX2020 Transmission	959.6		72.7		1.9		51
Other	10.6		2.3		—		50
Total	$	1,724.6	$	593.6	$	4.1

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

Components of regulatory assets:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	28.1	$	424.3	$	28.5	$	403.7
Net AROs (a)	1, 10	Plant lives	—		323.4		—		193.1
Excess deferred taxes - TCJA	7	Various	—		153.3		—		133.1
Recoverable deferred taxes on AFUDC recorded in plant		Plant lives	—		117.6		—		119.0
Benson biomass PPA termination and asset purchase		Ten years	9.8		85.8		—		—
Contract valuation adjustments (b)	1, 8	Term of related contract	14.1		76.0		14.4		89.8
Laurentian biomass PPA termination		Five years	18.1		73.3		—		—
PI extended power update		Sixteen years	3.1		55.8		3.3		58.4
Purchased power contracts costs		Term of related contract	2.8		36.6		1.8		39.3
Conservation programs (c)	1	One to two years	34.5		21.1		40.4		25.9
Losses on reacquired debt		Term of related debt	2.1		15.5		2.2		17.6
Environmental remediation costs	1, 10	Pending future rate cases	1.3		14.3		—		24.6
Nuclear refueling outage costs	1	One to two years	36.3		13.5		49.3		19.7
Deferred purchased natural gas and electric energy costs		One to three years	5.6		12.6		13.5		13.3
Sales true-up and revenue decoupling		One to two years	38.3		6.7		37.3		12.4
State commission adjustments		Plant lives	—		3.4		—		3.5
Renewable resources and environmental initiatives		One to two years	39.2		0.4		45.9		0.4
Gas pipeline inspection and remediation costs		Less than one year	27.4		—		22.6		4.5
Other		Various	19.6		20.5		17.2		32.1
Total regulatory assets			$	280.3	$	1,454.1	$	276.4	$	1,190.4

^(a)  Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

^(b)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(c)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Regulatory Liabilities

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	153.7	$	1,465.1	$	—	$	1,516.1
Plant removal costs	1, 10	Plant lives	—		484.6		—		441.6
ITC deferrals (b)	1	Various	—		8.9		—		9.5
Deferred electric energy costs		Less than one year	22.8		—		11.3		—
DOE Settlement		Less than one year	13.0		—		12.8		—
Contract valuation adjustments (c)	1, 8	Less than one year	10.4		—		17.2		—
Renewable resources and environmental initiatives		Less than one year	8.8		—		19.4		—
Other		Various	53.7		26.1		22.7		11.3
Total regulatory liabilities (d)			$	262.4	$	1,984.7	$	83.4	$	1,978.5

^(a)  Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

^(b)  Includes impact of lower federal tax rate due to the TCJA.

^(c)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(d)  Revenue subject for refund of $12.5 million and $15.1 million for 2018 and 2017, respectively, is included in other current liabilities.

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Money Pool [Table Text Block]

	Three Months Ended Dec. 31, 2018			Year Ended
(Amounts in Millions, Except Interest Rates)				2018			2017			2016
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	—			—			85			—
Average amount outstanding	18			17			25			16
Maximum amount outstanding	76			143			142			225
Weighted average interest rate, computed on a daily basis	2.23		%	1.96		%	1.14		%	0.69		%
Weighted average interest rate at period end	N/A			N/A			1.18			N/A

Short Term Debt

Commercial paper outstanding for NSP-Minnesota was as follows:

	Three Months Ended Dec. 31, 2018			Year Ended Dec. 31
(Amounts in Millions, Except Interest Rates)				2018			2017			2016
Borrowing limit	$	500		$	500		$	500		$	500
Amount outstanding at period end	150			150			20			85
Average amount outstanding	62			38			62			73
Maximum amount outstanding	198			198			237			353
Weighted average interest rate, computed on a daily basis	2.53		%	2.08		%	1.10		%	0.65		%
Weighted average interest rate at end of period	2.97			2.97			1.93			0.94

Schedule of Debt To Total Capitalization Ratio

Features of NSP-Minnesota’s credit facility:

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions)		Additional Periods For Which a One-Year Extension May Be Requested (b)
2018		2017
48	%	48	%	$	100	2

^(a)  The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

^(b)  All extension requests are subject to majority bank group approval

Credit Facilities

Dec. 31, 2018 (in millions):

Credit Facility (a)		Drawn(b)		Available
$	500	$	187	$	313

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

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

Schedule of Capitalization

ong term debt obligations for NSP-Minnesota as of Dec. 31:

(Millions of Dollars)	Maturity Range	Interest Rate Range 2018	Interest Rate Range 2017	2018			2017
NSP-Minnesota
Mortgage bonds	2020-2047	2.15% - 7.13%	2.15% - 7.13%	$	5,000		$	5,000
Unamortized discount				(21		)	(22		)
Unamortized debt issuance cost				(42		)	(45		)
Current maturities				—			—
Total				$	4,937		$	4,933

Schedule of Maturities of Long-term Debt

Maturities of long-term debt are as follows:

(Millions of Dollars)
2019	$	—
2020	300
2021	—
2022	300
2023	400

Schedule of Long-Term Debt Issuances

During 2018, NSP-Minnesota did not complete any new financings.

2017 financings:

	Amount	Financing Instrument	Interest Rate		Maturity Date
NSP-Minnesota	600 million	First mortgage bonds	3.60	%	Sept. 15, 2047

Dividend Payment Restrictions

Requirements and actuals as of Dec. 31, 2018:

	Equity to Total Capitalization Ratio - Required Range				Equity to Total Capitalization Ratio - Actual
	Low		High		2018
NSP-Minnesota	47.1	%	57.5	%	52.3	%

	Unrestricted Retained Earnings			Total Capitalization			Limit on Total Capitalization
NSP-Minnesota	$	1.0	billion	$	10.7	billion	$	11.5	billion

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Revenues Revenues (Tables)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

NSP-Minnesota’s operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following:

	Year Ended Dec. 31, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,308.4	$	308.8	$	27.2	$	1,644.4
C&I	2,052.1		239.3		0.2		2,291.6
Other	36.5		—		3.4		39.9
Total retail	3,397.0		548.1		30.8		3,975.9
Wholesale	189.2		—		—		189.2
Transmission	238.1		—		—		238.1
Interchange	473.7		—		—		473.7
Other	28.3		11.7		—		40.0
Total revenue from contracts with customers	4,326.3		559.8		30.8		4,916.9
Alternative revenue and other	181.7		23.3		—		205.0
Total revenues	$	4,508.0	$	583.1	$	30.8	$	5,121.9

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Interest Payable related to Unrecognized Tax Benefits

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)	2018			2017			2016
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.9	)	$	(2.0	)	$	(0.2	)
Interest (expense) income related to unrecognized tax benefits	(0.3		)	1.1			(1.8		)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(1.2	)	$	(0.9	)	$	(2.0	)

Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block]

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 consolidated federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2014	October 2019
2015	September 2019
2016	September 2020
2017	September 2021

Reconciliation of Unrecognized Tax Benefits

Unrecognized tax benefits - permanent vs temporary:

(Millions of Dollars)	Dec. 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	11.6	$	10.2
Unrecognized tax benefit — Temporary tax positions	5.3		7.9
Total unrecognized tax benefit	$	16.9	$	18.1

Changes in unrecognized tax benefits:

(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	18.1		$	60.8		$	55.4
Additions based on tax positions related to the current year	2.0			2.7			3.7
Reductions based on tax positions related to the current year	(0.3		)	(1.7		)	(0.2		)
Additions for tax positions of prior years	0.6			5.7			3.9
Reductions for tax positions of prior years	(1.1		)	(49.4		)	(2.0		)
Settlements with taxing authorities	(2.4		)	—			—
Balance at Dec. 31	$	16.9		$	18.1		$	60.8

Tax Benefits Associated with NOL and Tax Credit Carryforwards

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

(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(12.7	)	$	(12.8	)

NOL and Tax Credit Carryforwards

NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2018			2017
Federal NOL carryforward	$	—		$	631.6
Federal tax credit carryforwards	379.4			301.6
State NOL carryforwards	221.2			275.5
Valuation allowances for state NOL carryforwards	(0.8		)	(0.9		)
State tax credit carryforwards, net of federal detriment (a)	87.9			90.7
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(78.5		)	(82.2		)

^(a)  State tax credit carryforwards are net of federal detriment of $23.4 million and $24.1 million as of Dec. 31, 2018 and 2017, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $20.9 million and $21.8 million as of Dec. 31, 2018 and 2017, respectively.

Schedule of Effective Income Tax Rate Reconciliation

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:

	2018		2017 (a)		2016 (a)
Federal statutory rate	21.0	%	35.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	7.1		5.8		5.8
Increases (decreases) in tax from:
Wind PTCs recognized	(13.6	)	(11.4	)	(8.2	)
Regulatory differences - ARAM (b)	(9.1	)	(0.1	)	(0.1	)
Other tax credit recognized, net of federal income tax expense	(1.3	)	(1.0	)	(0.8	)
Regulatory differences - other utility plant items	0.3		(0.2	)	(0.2	)
Change in unrecognized tax benefits	0.1		(1.6	)	0.2
Tax reform	—		2.7		—
Other, net	0.7		(0.2	)	(0.2	)
Effective income tax rate	5.2	%	29.0	%	31.5	%

^(a)  Prior periods have been reclassified to conform to current year presentation.

^(b)  ARAM is a method to flow back excess deferred taxes to customers.

Schedule of Components of Income Tax Expense (Benefit)

Components of income tax expense for years ended Dec. 31:

(Millions of Dollars)	2018			2017			2016
Current federal tax (benefit) expense	$	(16.8	)	$	29.6		$	19.3
Current state tax expense	5.2			14.7			9.4
Current change in unrecognized tax (benefit) expense	(1.1		)	(36.2		)	1.3
Deferred federal tax (benefit) expense	(2.4		)	121.6			142.3
Deferred state tax expense	42.1			46.7			53.8
Deferred change in unrecognized tax expense	1.6			24.9			0.1
Deferred ITCs	(1.4		)	(1.6		)	(1.7		)
Total income tax expense	$	27.2		$	199.7		$	224.5

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)	2018			2017			2016
Deferred tax expense (benefit) excluding items below	$	70.1		$	(1,176.4	)	$	225.1
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(28.2		)	1,369.9			(28.7		)
Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other	(0.6		)	(0.3		)	(0.2		)
Deferred tax expense	$	41.3		$	193.2		$	196.2

Schedule of Deferred Tax Assets and Liabilities

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2018			2017
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,257.6		$	2,253.2
Regulatory assets	263.1			222.7
Pension expense	64.7			54.2
Other	11.3			16.4
Total deferred tax liabilities	$	2,596.7		$	2,546.5
Deferred tax assets:
Regulatory liabilities	$	382.8		$	386.6
Tax credit carryforward	467.3			392.4
NOL carryforward	17.9			153.5
NOL and tax credit valuation allowance	(78.6		)	(82.2		)
Other employee benefits	38.6			37.3
Deferred ITCs	6.4			6.8
Rate refund	49.7			6.6
Other	30.2			33.2
Total deferred tax assets	$	914.3		$	934.2
Net deferred tax liability	$	1,682.4		$	1,612.3

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Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

• 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:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted 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. The investments in commingled funds may be redeemed for NAV with proper 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, however, may be delayed or discounted as a result of fund illiquidity.

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

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

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations 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 forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as 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.

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

Non-Derivative Fair Value Measurements

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other 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 over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.

Unrealized gains for the nuclear decommissioning fund were $450.1 million and $559.9 million as of Dec. 31, 2018 and 2017, respectively, and unrealized losses were $44.8 million and $7.4 million as of Dec. 31, 2018 and 2017, respectively.

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

	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 $52.5 million of rabbi trust assets and miscellaneous investments.

	Dec. 31, 2017
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	28.7	$	28.7	$	—	$	—	$	—	$	28.7
Commingled funds	701.3		222.8		—		—		659.1		$	881.9
Debt securities	437.7		—		441.6		—		—		$	441.6
Equity securities	423.1		791.1		—		—		—		$	791.1
Total	$	1,590.8	$	1,042.6	$	441.6	$	—	$	659.1	$	2,143.3

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $49.1 million of rabbi trust assets and miscellaneous investments.

For the years ended Dec. 31, 2018 and 2017, there were no Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2018:

	Final Contractual Maturity
(Millions of Dollars)	Due in 1Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	10.6	$	106.9	$	210.5	$	107.6	$	435.6

Rabbi Trusts

NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions.

Cost and fair value of assets held in rabbi trusts:

	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, 2017
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	0.8	$	0.8	$	—	$	—	$	0.8
Mutual funds	10.3		11.3		—		—		$	11.3
Total	$	11.1	$	12.1	$	—	$	—	$	12.1

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

Derivative 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.

As of Dec. 31, 2018, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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

As of Dec. 31, 2018, NSP-Minnesota had no vehicle fuel contracts designated as cash flow hedges. NSP-Minnesota 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 in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Immaterial amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2018 and 2017.

As of Dec. 31, 2018, there were no net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.

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

Gross notional amounts of commodity forwards, options and FTRs at Dec. 31:

(Amounts in Millions)(a) (b)	2018	2017
MWh of electricity	56.8	41.7
MMBtu of natural gas	42.7	23.8
Gallons of vehicle fuel	—	0.2

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

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. As of Dec. 31, 2018, six of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $35.9 million or 44% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.

Two of the 10 most significant counterparties, comprising $14.4 million or 18% 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. One of the 10 most significant counterparties, comprising $1.3 million or 2% of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. One of the 10 most significant counterparties, comprising $11.8 million or 14% of this credit exposure, had credit quality less than investment grade based on rating from internal analysis. Seven of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)	2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(20.9	)	$	(18.2	)	$	(19.1	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			0.1			—
After-tax net realized losses on derivative transactions reclassified into earnings	0.7			0.9			0.9
Adoption of ASU. 2018-02 (a)	—			(3.7		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(20.2	)	$	(20.9	)	$	(18.2	)

^(a)  In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

Impact of derivative activity:

	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2018
Other derivative instruments
Electric commodity	$	—	$	(5.5	)
Natural gas commodity	—		1.8
Total	$	—	$	(3.7	)
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Vehicle fuel and other commodity	$	0.1	$	—
Total	$	0.1	$	—
Other derivative instruments
Electric commodity	$	—	$	9.3
Natural gas commodity	—		(1.9		)
Total	$	—	$	7.4
Year Ended Dec. 31, 2016
Other derivative instruments
Electric commodity	—		14.4
Natural gas commodity	—		(1.2		)
Total	$	—	$	13.2

	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)
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1.1		(a)	$	—			$	—
Vehicle fuel and other commodity	(0.1		)	(b)	—				—
Total	$	1.0			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	10.9		(c)
Electric commodity	—				3.3			(d)	—
Natural gas commodity	—				(1.9		)	(e)	(1.3		)	(e)
Total	$	—			$	1.4			$	9.6
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Interest rate	$	1.5		(a)	$	—			$	—
Total	$	1.5			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	9.4		(c)
Electric commodity	—				(13.8		)	(d)	—
Natural gas commodity	—				1.0			(e)	(1.2		)	(e)
Total	$	—			$	(12.8	)		$	8.2
Year Ended Dec. 31, 2016
Derivatives designated as cash flow hedges
Interest rate	$	1.4		(a)	$	—			$	—
Vehicle fuel and other commodity	0.1			(b)	—				—
Total	$	1.5			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	2.8		(c)
Electric commodity	—				(6.1		)	(d)	—
Natural gas commodity	—				4.0			(e)	(2.2		)	(e)
Total	$	—			$	(2.1	)		$	0.6

^(a)  Amounts are recorded to interest charges.

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

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

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

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

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2018, 2017 and 2016.

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 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 if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2018 and 2017, there were no derivative instruments in a liability position with such underlying contract provisions.

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

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2018 and 2017:

	Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total		Netting (a)					Fair Value						Fair Value Total		Netting (a)
(Millions of Dollars)	Level 1		Level 2		Level 3							Total		Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	—	$	—	$	—	$	—		$	—	$	—	$	0.1	$	—	$	0.1	$	—		$	0.1
Other derivative instruments:
Commodity trading	1.1		27.1		2.2		30.4		(16.0		)	14.4		1.7		17.1		0.1		18.9		(11.7		)	7.2
Electric commodity	—		—		10.5		10.5		(0.1		)	10.4		—		—		17.6		17.6		(0.4		)	17.2
Natural gas commodity	—		1.0		—		1.0		—			1.0		—		0.1		—		0.1		—			0.1
Total current derivative assets	$	1.1	$	28.1	$	12.7	$	41.9	$	(16.1	)	25.8		$	1.7	$	17.3	$	17.7	$	36.7	$	(12.1	)	24.6
PPAs (b)												—													0.6
Current derivative instruments												$	25.8												$	25.2
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	25.3	$	5.0	$	30.3	$	(13.4	)	$	16.9	$	—	$	29.1	$	5.4	$	34.5	$	(6.5	)	$	28.0
Total noncurrent derivative assets	$	—	$	25.3	$	5.0	$	30.3	$	(13.4	)	16.9		$	—	$	29.1	$	5.4	$	34.5	$	(6.5	)	28.0
PPAs (b)												0.1													0.1
Noncurrent derivative instruments												$	17.0												$	28.1

	Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total		Netting (a)					Fair Value						Fair Value Total		Netting (a)
(Millions of Dollars)	Level 1		Level 2		Level 3							Total		Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1.4	$	23.9	$	1.7	$	27.0	$	(24.5	)	$	2.5	$	1.7	$	13.9	$	—	$	15.6	$	(12.0	)	$	3.6
Electric commodity	—		—		0.1		0.1		(0.1		)	—		—		—		0.4		0.4		(0.4		)	—
Total current derivative liabilities	$	1.4	$	23.9	$	1.8	$	27.1	$	(24.6	)	2.5		$	1.7	$	13.9	$	0.4	$	16.0	$	(12.4	)	3.6
PPAs (b)												14.0													14.1
Current derivative instruments												$	16.5												$	17.7
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	0.1	$	16.0	$	1.6	$	17.7	$	17.9		$	35.6	$	—	$	22.2	$	—	$	22.2	$	(9.4	)	$	12.8
Total noncurrent derivative liabilities	$	0.1	$	16.0	$	1.6	$	17.7	$	17.9		35.6		$	—	$	22.2	$	—	$	22.2	$	(9.4	)	12.8
PPAs (b)												76.6													89.9
Noncurrent derivative instruments												$	112.2												$	102.7

^(a)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2018 and 2017. At Dec. 31, 2018 and 2017, derivative assets and liabilities include $31.5 million and $0 million of obligations to return cash collateral, respectively. At Dec. 31, 2018 and 2017, derivative assets and liabilities include the rights to reclaim cash collateral of $8.7 million and $3.1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  During 2006, 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.

Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2018, 2017 and 2016:

	Year Ended Dec. 31
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	22.6		$	15.3		$	13.0
Purchases	26.4			40.6			28.0
Settlements	(17.2		)	(41.7		)	(47.2		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(1.5		)	5.5			—
Net (losses) gains recognized as regulatory assets and liabilities	(16.0		)	2.9			21.5
Balance at Dec. 31	$	14.3		$	22.6		$	15.3

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

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended 2016 - 2018.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

	2018				2017
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,937.2	$	5,230.9	$	4,933.0	$	5,601.9

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

Cost and Fair Value of Nuclear Decommissioning Fund Investments

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

	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 $52.5 million of rabbi trust assets and miscellaneous investments.

	Dec. 31, 2017
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	28.7	$	28.7	$	—	$	—	$	—	$	28.7
Commingled funds	701.3		222.8		—		—		659.1		$	881.9
Debt securities	437.7		—		441.6		—		—		$	441.6
Equity securities	423.1		791.1		—		—		—		$	791.1
Total	$	1,590.8	$	1,042.6	$	441.6	$	—	$	659.1	$	2,143.3

^(a)  Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $49.1 million of rabbi trust assets and miscellaneous investments.

Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2018:

	Final Contractual Maturity
(Millions of Dollars)	Due in 1Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	10.6	$	106.9	$	210.5	$	107.6	$	435.6

Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block]

Rabbi Trusts

NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions.

Cost and fair value of assets held in rabbi trusts:

	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, 2017
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	0.8	$	0.8	$	—	$	—	$	0.8
Mutual funds	10.3		11.3		—		—		$	11.3
Total	$	11.1	$	12.1	$	—	$	—	$	12.1

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

Gross Notional Amounts of Commodity Forwards, Options, and FTRs

Gross notional amounts of commodity forwards, options and FTRs at Dec. 31:

(Amounts in Millions)(a) (b)	2018	2017
MWh of electricity	56.8	41.7
MMBtu of natural gas	42.7	23.8
Gallons of vehicle fuel	—	0.2

^(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.

Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss

Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)	2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(20.9	)	$	(18.2	)	$	(19.1	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			0.1			—
After-tax net realized losses on derivative transactions reclassified into earnings	0.7			0.9			0.9
Adoption of ASU. 2018-02 (a)	—			(3.7		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(20.2	)	$	(20.9	)	$	(18.2	)

^(a)  In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income

Impact of derivative activity:

	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2018
Other derivative instruments
Electric commodity	$	—	$	(5.5	)
Natural gas commodity	—		1.8
Total	$	—	$	(3.7	)
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Vehicle fuel and other commodity	$	0.1	$	—
Total	$	0.1	$	—
Other derivative instruments
Electric commodity	$	—	$	9.3
Natural gas commodity	—		(1.9		)
Total	$	—	$	7.4
Year Ended Dec. 31, 2016
Other derivative instruments
Electric commodity	—		14.4
Natural gas commodity	—		(1.2		)
Total	$	—	$	13.2

	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)
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1.1		(a)	$	—			$	—
Vehicle fuel and other commodity	(0.1		)	(b)	—				—
Total	$	1.0			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	10.9		(c)
Electric commodity	—				3.3			(d)	—
Natural gas commodity	—				(1.9		)	(e)	(1.3		)	(e)
Total	$	—			$	1.4			$	9.6
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Interest rate	$	1.5		(a)	$	—			$	—
Total	$	1.5			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	9.4		(c)
Electric commodity	—				(13.8		)	(d)	—
Natural gas commodity	—				1.0			(e)	(1.2		)	(e)
Total	$	—			$	(12.8	)		$	8.2
Year Ended Dec. 31, 2016
Derivatives designated as cash flow hedges
Interest rate	$	1.4		(a)	$	—			$	—
Vehicle fuel and other commodity	0.1			(b)	—				—
Total	$	1.5			$	—			$	—
Other derivative instruments
Commodity trading	$	—			$	—			$	2.8		(c)
Electric commodity	—				(6.1		)	(d)	—
Natural gas commodity	—				4.0			(e)	(2.2		)	(e)
Total	$	—			$	(2.1	)		$	0.6

^(a)  Amounts are recorded to interest charges.

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

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

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

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

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2018 and 2017:

	Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total		Netting (a)					Fair Value						Fair Value Total		Netting (a)
(Millions of Dollars)	Level 1		Level 2		Level 3							Total		Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	—	$	—	$	—	$	—		$	—	$	—	$	0.1	$	—	$	0.1	$	—		$	0.1
Other derivative instruments:
Commodity trading	1.1		27.1		2.2		30.4		(16.0		)	14.4		1.7		17.1		0.1		18.9		(11.7		)	7.2
Electric commodity	—		—		10.5		10.5		(0.1		)	10.4		—		—		17.6		17.6		(0.4		)	17.2
Natural gas commodity	—		1.0		—		1.0		—			1.0		—		0.1		—		0.1		—			0.1
Total current derivative assets	$	1.1	$	28.1	$	12.7	$	41.9	$	(16.1	)	25.8		$	1.7	$	17.3	$	17.7	$	36.7	$	(12.1	)	24.6
PPAs (b)												—													0.6
Current derivative instruments												$	25.8												$	25.2
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	25.3	$	5.0	$	30.3	$	(13.4	)	$	16.9	$	—	$	29.1	$	5.4	$	34.5	$	(6.5	)	$	28.0
Total noncurrent derivative assets	$	—	$	25.3	$	5.0	$	30.3	$	(13.4	)	16.9		$	—	$	29.1	$	5.4	$	34.5	$	(6.5	)	28.0
PPAs (b)												0.1													0.1
Noncurrent derivative instruments												$	17.0												$	28.1

	Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total		Netting (a)					Fair Value						Fair Value Total		Netting (a)
(Millions of Dollars)	Level 1		Level 2		Level 3							Total		Level 1		Level 2		Level 3							Total
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1.4	$	23.9	$	1.7	$	27.0	$	(24.5	)	$	2.5	$	1.7	$	13.9	$	—	$	15.6	$	(12.0	)	$	3.6
Electric commodity	—		—		0.1		0.1		(0.1		)	—		—		—		0.4		0.4		(0.4		)	—
Total current derivative liabilities	$	1.4	$	23.9	$	1.8	$	27.1	$	(24.6	)	2.5		$	1.7	$	13.9	$	0.4	$	16.0	$	(12.4	)	3.6
PPAs (b)												14.0													14.1
Current derivative instruments												$	16.5												$	17.7
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	0.1	$	16.0	$	1.6	$	17.7	$	17.9		$	35.6	$	—	$	22.2	$	—	$	22.2	$	(9.4	)	$	12.8
Total noncurrent derivative liabilities	$	0.1	$	16.0	$	1.6	$	17.7	$	17.9		35.6		$	—	$	22.2	$	—	$	22.2	$	(9.4	)	12.8
PPAs (b)												76.6													89.9
Noncurrent derivative instruments												$	112.2												$	102.7

^(a)  NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2018 and 2017. At Dec. 31, 2018 and 2017, derivative assets and liabilities include $31.5 million and $0 million of obligations to return cash collateral, respectively. At Dec. 31, 2018 and 2017, derivative assets and liabilities include the rights to reclaim cash collateral of $8.7 million and $3.1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  During 2006, 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.

Changes in Level 3 Commodity Derivatives

Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2018, 2017 and 2016:

	Year Ended Dec. 31
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	22.6		$	15.3		$	13.0
Purchases	26.4			40.6			28.0
Settlements	(17.2		)	(41.7		)	(47.2		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(1.5		)	5.5			—
Net (losses) gains recognized as regulatory assets and liabilities	(16.0		)	2.9			21.5
Balance at Dec. 31	$	14.3		$	22.6		$	15.3

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

Carrying Amount and Fair Value of Long-term Debt

	2018				2017
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,937.2	$	5,230.9	$	4,933.0	$	5,601.9

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Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2018

Benefit Plans and Other Postretirement Benefits [Abstract]

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	502.0		$	545.3		$	34.3		$	45.3
Prior service (credit) cost	(1.2		)	(1.3		)	(12.4		)	(15.4		)
Total	$	500.8		$	544.0		$	21.9		$	29.9
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	35.5		$	37.7		$	—		$	—
Noncurrent regulatory assets	465.3			506.3			20.5			28.0
Deferred income taxes	—			—			0.4			0.5
Net-of-tax accumulated other comprehensive income	—			—			1.0			1.4
Total	$	500.8		$	544.0		$	21.9		$	29.9
Measurement date	Dec. 31, 2018			Dec. 31, 2017			Dec. 31, 2018			Dec. 31, 2017

Projected Benefit Payments for the Pension and Postretirement Benefit Plans

Projected Benefit Payments

NSP-Minnesota’s projected benefit payments:

(Millions of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2019	$	93.4	$	7.2	$	—	$	7.2
2020	81.2		7.0		—		7.0
2021	80.1		6.7		—		6.7
2022	79.0		6.3		—		6.3
2023	77.2		6.0		—		6.0
2024-2027	342.3		26.0		—		26.0

Pension Plan

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

The following presents, for each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value:

	Dec. 31, 2018 (a)												Dec. 31, 2017 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV			Total			Level 1			Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	31.8	$	—	$	—	$	—		$	31.8		$	53.4		$	—	$	—	$	—	$	53.4
Commingled funds:	241.0		—		—		271.2			512.2			285.2			—		—		302.4		587.6
Debt securities:	—		143.7		—		—			143.7			—			159.0		—		—		159.0
Equity securities:	29.3		—		—		—			29.3			32.1			—		—		—		32.1
Other	0.5		1.3		—		(8.2		)	(6.4		)	(8.7		)	1.0		—		0.1		$	(7.6	)
Total	$	302.6	$	145.0	$	—	$	263.0		$	710.6		$	362.0		$	160.0	$	—	$	302.5	$	824.5

^(a)  See Note 8 for further information on fair value measurement inputs and methods.

The following presents, for each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value:

	Dec. 31, 2018 (a)										Dec. 31, 2017 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	0.1	$	—	$	—	$	—	$	0.1	$	0.4	$	—	$	—	$	—	$	0.4
Insurance contracts	—		0.3		—		—		0.3		—		0.7		—		—		0.7
Commingled funds	0.8		—		—		0.2		1.0		2.1		—		—		—		2.1
Debt securities	—		1.0		—		—		1.0		—		2.8		—		—		2.8
Equity securities	—		—		—		—		—		0.5		—		—		—		0.5
Total	$	0.9	$	1.3	$	—	$	0.2	$	2.4	$	3.0	$	3.5	$	—	$	—	$	6.5

Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]

	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,035.1		$	1,036.5		$	88.8		$	86.7
Service cost	28.0			27.8			0.2			0.1
Interest cost	35.2			40.7			3.1			3.4
Plan amendments	—			(4.4		)	—			—
Actuarial (gain) loss	(50.8		)	64.1			(9.0		)	5.9
Plan participants’ contributions	—			—			0.4			0.4
Benefit payments (a)	(140.5		)	(129.6		)	(7.5		)	(7.7		)
Obligation at Dec. 31	$	907.0		$	1,035.1		$	76.0		$	88.8
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	824.5		$	783.2		$	6.5		$	3.7
Actual return on plan assets	(36.5		)	110.1			—			—
Employer contributions	63.1			60.7			3.0			10.1
Plan participants’ contributions	—			—			0.4			0.4
Benefit payments	(140.5		)	(129.5		)	(7.5		)	(7.7		)
Fair value of plan assets at Dec. 31	$	710.6		$	824.5		$	2.4		$	6.5
Funded status of plans at Dec. 31	$	(196.4	)	$	(210.6	)	$	(73.6	)	$	(82.3	)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Current assets (liabilities)	$	—		$	—		$	(4.8	)	$	(1.3	)
Noncurrent assets (liabilities)	(196.4		)	(210.6		)	(68.8		)	(81.0		)
Net amounts recognized	$	(196.4	)	$	(210.6	)	$	(73.6	)	$	(82.3	)

^(a)  Includes approximately $105 million of lump-sum benefit payments used in the determination of a settlement charge.

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.31	%	3.63	%	4.32	%	3.62	%
Expected average long-term increase in compensation level	3.75	%	3.75	%	N/A		N/A
Mortality table	RP-2014		RP-2014		RP-2014		RP-2014
Health care costs trend rate — initial: Pre-65	N/A		N/A		6.50	%	7.00	%
Health care costs trend rate — initial: Post-65	N/A		N/A		5.30	%	5.50	%
Ultimate trend assumption — initial: Pre-65	N/A		N/A		4.50	%	4.50	%
Ultimate trend assumption — initial: Post-65	N/A		N/A		4.50	%	4.50	%
Years until ultimate trend is reached	N/A		N/A		4		5

Components of Net Periodic Benefit Costs

	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2018			2017			2016			2018			2017			2016
Service cost	$	28.0		$	27.8		$	28.3		$	0.2		$	0.1		$	0.1
Interest cost	35.2			40.7			45.4			3.1			3.4			3.9
Expected return on plan assets	(58.2		)	(60.1		)	(60.9		)	(0.4		)	(0.2		)	(0.2		)
Amortization of prior service cost	(0.1		)	1.1			0.9			(3.0		)	(3.0		)	(3.0		)
Amortization of net loss	38.5			39.6			36.8			2.4			2.0			1.6
Settlement charge (a)	48.8			48.2			—			—			—			—
Net periodic pension cost	92.2			97.3			50.5			2.3			2.3			2.4
Costs not recognized due to effects of regulation	(66.0		)	(72.2		)	(20.9		)	—			—			—
Net benefit cost recognized for financial reporting	$	26.2		$	25.1		$	29.6		$	2.3		$	2.3		$	2.4
Significant Assumptions Used to Measure Costs:
Discount rate	3.63		%	4.13		%	4.66		%	3.62		%	4.13		%	4.65		%
Expected average long-term increase in compensation level	3.75			3.75			4.00			—			—			—
Expected average long-term rate of return on assets	7.10			7.10			7.10			5.30			5.80			5.80

^(a)  A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of $48.8 million in 2018 and $48.2 million in 2017,

Postretirement Benefits Plan

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

Target asset allocations:

	Pension Benefits				Postretirement Benefits
	2018		2017		2018		2017
Domestic and international equity securities	37	%	38	%	18	%	24	%
Long-duration fixed income and interest rate swap securities	28		23		—		—
Short-to-intermediate fixed income securities	18		21		70		60
Alternative investments	15		16		8		9
Cash	2		2		4		7
Total	100	%	100	%	100	%	100	%

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Estimated Minimum Purchases Under Fuel Contracts

Estimated minimum purchases for these contracts as of Dec. 31, 2018:

(Millions of Dollars)	Coal		Nuclear fuel		Natural gas supply		Natural gas storage and transportation
2019	$	194.7	$	127.1	$	43.6	$	107.4
2020	87.4		50.9		1.4		97.5
2021	52.0		99.0		1.4		95.6
2022	34.7		78.5		0.8		92.6
2023	35.1		99.4		—		82.8
Thereafter	3.5		337.1		—		320.7
Total (a)	$	407.4	$	792.0	$	47.2	$	796.6

^(a)  Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements

At Dec. 31, 2018, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)	Capacity		Energy (a)
2019	$	54.0	$	98.7
2020	54.6		109.4
2021	62.2		157.4
2022	61.3		172.9
2023	62.7		176.9
Thereafter	109.5		328.1
Total (b)	$	404.3	$	1,043.4

^(a)  Excludes contingent energy payments for renewable energy PPAs.

^(b)  Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Future Commitments Under Operating Leases

Future commitments under operating leases:

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

^(a)  Amounts do not include PPAs accounted for as executory contracts.

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

Guarantees Issued and Outstanding

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

(Millions of Dollars)	Guarantor	Guarantee Amount		Current Exposure		Triggering Event
Guarantee of residual value of assets under the Bank of Tokyo-Mitsubishi Capital Corporation Equipment Leasing Agreement	NSP-Minnesota	$	4.8	$	—	(a)

^(a)  Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term in 2019.

Asset Retirement Obligations

NSP-Minnesota’s AROs were as follows:

	Dec. 31, 2018
(Millions of Dollars)	Jan. 1, 2018		Amounts Settled (a)			Accretion		Cash Flow Revisions (b)			Dec. 31, 2018(c)
Electric
Nuclear	$	1,873.6	$	—		$	94.7	$	—		$	1,968.3
Wind	94.1		—			4.3		6.5			104.9
Steam and other production	64.0		(6.6		)	2.1		(10.3		)	49.2
Distribution	5.8		—			0.2		8.5			14.5
Miscellaneous	1.9		—			—		(0.1		)	1.8
Natural gas
Transmission and distribution	43.6		—			1.8		(7.2		)	38.2
Miscellaneous	0.2		—			—		—			0.2
Common
Miscellaneous	0.7		—			0.1		—			0.8
Total liability	$	2,083.9	$	(6.6	)	$	103.2	$	(2.6	)	$	2,177.9

^(a)  Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

^(b)  In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.

^(c)  There were no ARO amounts incurred in 2018.

	Dec. 31, 2017
(Millions of Dollars)	Jan. 1, 2017		Amounts Settled (a)			Accretion		Cash Flow Revisions (b)			Dec. 31, 2017 (c)
Electric
Nuclear	$	2,249.3	$	—		$	113.8	$	(489.5	)	$	1,873.6
Wind	90.1		—			4.0		—			94.1
Steam and other production	68.5		(4.9		)	2.4		(2.0		)	64.0
Distribution	5.6		—			0.2		—			5.8
Miscellaneous	1.8		—			0.1		—			1.9
Natural gas
Transmission and distribution	35.8		—			1.5		6.3			43.6
Miscellaneous	0.2		—			—		—			0.2
Common
Miscellaneous	1.3		(0.6		)	—		—			0.7
Total liability	$	2,452.6	$	(5.5	)	$	122.0	$	(485.2	)	$	2,083.9

^(a)  Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

^(b)  In 2017, AROs were revised for changes in timing and estimates of cash flows. Nuclear AROs decreased due to updated assumptions in the nuclear triennial filing.

^(c)  There were no ARO amounts incurred in 2017.

Funded Status of Nuclear Decommissioning Obligation

The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements (ARO).

	Regulatory Basis
(Millions of Dollars)	2018			2017
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)	$	3,012.3		$	3,012.3
Effect of escalating costs	538.9			395.7
Estimated decommissioning cost obligation (in current dollars)	3,551.2			3,408.0
Effect of escalating costs to payment date	7,654.3			7,797.5
Estimated future decommissioning costs (undiscounted)	11,205.5			11,205.5
Effect of discounting obligation (using average risk-free interest rate of 3.33% and 2.80% for 2018 and 2017, respectively)	(6,911.5		)	(6,398.1		)
Discounted decommissioning cost obligation	$	4,294.0		$	4,807.4
Assets held in external decommissioning trust	$	2,054.7		$	2,143.3
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation	2,239.3			2,664.1

Reconciliation of Decommissioning Cost Obligation - Regulatory to GAAP

Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:

(Millions of Dollars)	2018			2017
Discounted decommissioning cost obligation - regulated basis	$	4,294.0		$	4,807.4
Differences in discount rate and market risk premium	(1,446.4		)	(1,402.8		)
O&M costs not included for GAAP	(879.3		)	(1,041.5		)
ARO differences between 2017 and 2014 cost studies	—			(489.5		)
Nuclear production decommissioning ARO - GAAP	$	1,968.3		$	1,873.6

Nuclear Decommissioning Expenses Recognized as Result of Regulation

Decommissioning expenses recognized as a result of regulation:

(Millions of Dollars)	2018		2017		2016
Annual decommissioning recorded as depreciation expense: (a) (b)	$	20.4	$	20.4	$	20.4

^(a)  Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

^(b)  Decommissioning expenses in 2018, 2017 and 2016 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14.0 million.

Total expense for energy and capacity payments table text block [Table Text Block]

Total expenses (including capacity payments) under operating lease obligations for NSP-Minnesota and the corresponding capacity payments for PPAs accounted for as operating leases for the year ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Total expense	$	76.2	$	76.9	$	79.1
Capacity payments	62.5		62.7		63.4

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Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2018

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax

	2017
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(18.2	)		$	0.1	$	(2.7	)		$	(20.8	)
Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0, and $0.1, respectively)	0.1				—		(0.5		)		(0.4		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.6, $0, and $0, respectively)	0.9			(a)	—		—				0.9
Amortization of net actuarial loss (net of taxes of $0, $0, and $0.1, respectively)	—				—		0.1			(b)	0.1
Net current period other comprehensive income (loss)	1.0				—		(0.4		)		0.6
Adoption of ASU No. 2018-02 (c)	(3.7		)		—		(0.6		)		(4.3		)
Accumulated other comprehensive (loss) income at Dec. 31	$	(20.9	)		$	0.1	$	(3.7	)		$	(24.5	)

	2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(20.9	)		$	0.1		$	(3.7	)		$	(24.5	)
Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0, and $0.3 respectively)	—				(0.1		)	0.6				0.5
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.3, $0, and $0, respectively) (a)	0.7			(a)	—			—				0.7
Amortization of net actuarial loss (net of taxes of $0, $0, and $0.1, respectively)	—				—			0.2			(b)	0.2
Net current period other comprehensive income (loss)	0.7				(0.1		)	0.8				1.4
Accumulated other comprehensive loss at Dec. 31	$	(20.2	)		$	—		$	(2.9	)		$	(23.1	)

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Results from Operations by Reportable Segment

(Millions of Dollars)	2018			2017			2016
Regulated Electric
Operating revenues (a)	$	4,508.0		$	4,541.8		$	4,404.6
Intersegment revenues	0.8			0.6			0.6
Total operating revenue	$	4,508.8		$	4,542.4		$	4,405.2
Depreciation and amortization	697.8			661.3			554.3
Interest charges and financing costs	199.5			199.8			200.8
Income tax expense	16.4			179.9			215.5
Net income	450.4			462.5			465.4
Regulated Natural Gas
Operating revenues (a)	$	583.1		$	531.9		$	467.4
Intersegment revenues	0.5			0.5			0.5
Total operating revenue	$	583.6		$	532.4		$	467.9
Depreciation and amortization	43.3			38.7			41.8
Interest charges and financing costs	14.8			13.5			13.2
Income tax expense	10.2			10.0			12.0
Net income	34.2			28.4			18.3
All Other
Operating revenues (a)	$	30.8		$	28.3		$	28.3
Depreciation and amortization	0.5			0.6			0.6
Interest charges and financing costs	—			—			—
Income tax expense	0.6			9.8			(3.0		)
Net income	7.7			(0.8		)	5.0
Consolidated Total
Total operating revenue	$	5,123.2		$	5,103.1		$	4,901.4
Reconciling eliminations	(1.3		)	(1.1		)	(1.1		)
Consolidated total revenue	$	5,121.9		$	5,102.0		$	4,900.3
Depreciation and amortization	741.6			700.6			596.7
Interest charges and financing costs	214.3			213.3			214.0
Income tax expense	27.2			199.7			224.5
Net income	492.3			490.1			488.7

^(a)  Operating revenues include $473.7 million, $490.2 million, and $475.5 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 13 for further information.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Operating revenues:
Electric	$	473.7	$	490.2	$	475.5
Operating expenses:
Purchased power	61.1		66.8		63.0
Transmission expense	96.8		110.5		107.5
Other operating expenses — paid to Xcel Energy Services Inc.	534.8		539.4		513.0
Interest expense	0.3		—		—

Accounts receivable and payable with affiliates at Dec. 31 were:

	2018				2017
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Wisconsin	$	11.0	$	—	$	17.8	$	—
PSCo	—		17.9		—		7.7
SPS	—		4.7		—		1.0
Other subsidiaries of Xcel Energy Inc.	—		87.1		30.7		71.4
	$	11.0	$	109.7	$	48.5	$	80.1

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Millions of Dollars)	March 31, 2018		June 30, 2018		Sept. 30, 2018		Dec. 31, 2018
Operating revenues	$	1,310.8	$	1,187.7	$	1,351.8	$	1,271.6
Operating income	171.4		150.1		259.5		135.5
Net income	111.7		92.4		201.2		87.0

	Quarter Ended
(Millions of Dollars)	March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
Operating revenues	$	1,307.1	$	1,164.9	$	1,355.8	$	1,274.2
Operating income (a)	182.5		173.1		339.7		187.4
Net income	94.2		87.7		229.0		79.3

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Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.60%	3.60%	3.20%
Nuclear Decommissioning [Abstract]
Minimum amount of time between nuclear decommissioning studies (in years)	3 years
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents	3 months
Accounts, Notes, Loans and Financing Receivable, Classified [Abstract]
Allowance for bad debts	$ 23.5	$ 21.3
Alternative Revenue Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Public Utilities, Inventory [Line Items]
Inventories	$ 299.4	337.7
Supplies
Public Utilities, Inventory [Line Items]
Inventories	176.3	209.2
Public Utilities, Inventory, Fuel
Public Utilities, Inventory [Line Items]
Inventories	88.5	94.5
Public Utilities, Inventory, Natural Gas
Public Utilities, Inventory [Line Items]
Inventories	$ 34.6	$ 34.0

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Accounting Pronouncements Adoption of New Accounting Pronouncements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Other Expense | Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 14.8	$ 13.6

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Property Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 20,643.0	$ 19,649.4
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	7,454.8	7,018.2
Property, Plant and Equipment, Net	13,541.7	13,033.6
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment	17,749.3	17,024.9
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,475.5	1,370.3
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment	803.1	724.1
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment	615.1	530.1
Nuclear fuel
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,770.4	2,697.4
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 2,416.9	$ 2,295.0

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Property Plant and Equipment Property Plant and Equipment Joint Ownership (Details) - NSP Minnesota $ in Millions	Dec. 31, 2018 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,724.6
Accumulated Depreciation	593.6
CWIP	4.1
Electric Generation | Sherco Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	604.2
Accumulated Depreciation	415.0
CWIP	$ 1.0
Ownership percentage (in hundredths)	59.00%
Electric Generation | Sherco Common Facilities Units 1, 2 and 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 145.4
Accumulated Depreciation	100.2
CWIP	$ 1.2
Ownership percentage (in hundredths)	80.00%
Electric Generation | Sherco Substation
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 4.8
Accumulated Depreciation	3.4
CWIP	$ 0.0
Ownership percentage (in hundredths)	59.00%
Electric Transmission | Grand Meadow Line and Substation
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 959.6
Accumulated Depreciation	72.7
CWIP	$ 1.9
Ownership percentage (in hundredths)	51.00%
Electric Transmission | CapX2020 Transmission
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 10.6
Accumulated Depreciation	2.3
CWIP	$ 0.0
Ownership percentage (in hundredths)	50.00%

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Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 280.3	$ 276.4
Regulatory Asset, Noncurrent		1,454.1	1,190.4
Past expenditures not currently earning a return		149.0	142.0
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		28.1	28.5
Regulatory Asset, Noncurrent		$ 424.3	403.7
Regulatory asset, remaining amortization period		Various
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[1]	$ 0.0	0.0
Regulatory Asset, Noncurrent	[1]	$ 323.4	193.1
Regulatory asset, remaining amortization period		Plant lives
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0.0	0.0
Regulatory Asset, Noncurrent		$ 153.3	133.1
Regulatory asset, remaining amortization period		Various
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0.0	0.0
Regulatory Asset, Noncurrent		$ 117.6	119.0
Regulatory asset, remaining amortization period		Plant lives
Benson purchase power agreement termination and asset purchase
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 9.8	0.0
Regulatory Asset, Noncurrent		$ 85.8	0.0
Regulatory Asset, Amortization Period		10 years
Contract Valuation Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	$ 14.1	14.4
Regulatory Asset, Noncurrent	[2]	$ 76.0	89.8
Regulatory asset, remaining amortization period		Term of related contract
Laurentian Energy Authority purchase power agreement termination
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 18.1	0.0
Regulatory Asset, Noncurrent		$ 73.3	0.0
Regulatory Asset, Amortization Period		5 years
Prairie Island EPU
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 3.1	3.3
Regulatory Asset, Noncurrent		$ 55.8	58.4
Regulatory Asset, Amortization Period		16 years
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 2.8	1.8
Regulatory Asset, Noncurrent		$ 36.6	39.3
Regulatory asset, remaining amortization period		Term of related contract
Conservation Programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[3]	$ 34.5	40.4
Regulatory Asset, Noncurrent	[3]	$ 21.1	25.9
Regulatory Asset Amortization Period, minimum		1 year
Regulatory Asset Amortization Period, maximum		2 years
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 2.1	2.2
Regulatory Asset, Noncurrent		$ 15.5	17.6
Regulatory asset, remaining amortization period		Term of related debt
Environmental Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 1.3	0.0
Regulatory Asset, Noncurrent		$ 14.3	24.6
Regulatory asset, remaining amortization period		Pending future rate cases
Nuclear Refueling Outage Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 36.3	49.3
Regulatory Asset, Noncurrent		$ 13.5	19.7
Regulatory Asset Amortization Period, minimum		1 year
Regulatory Asset Amortization Period, maximum		2 years
Deferred Purchased Natural Gas and Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 5.6	13.5
Regulatory Asset, Noncurrent		$ 12.6	13.3
Regulatory Asset Amortization Period, minimum		1 year
Regulatory Asset Amortization Period, maximum		3 years
Sales True Up and Revenue Decoupling
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 38.3	37.3
Regulatory Asset, Noncurrent		$ 6.7	12.4
Regulatory Asset Amortization Period, minimum		1 year
Regulatory Asset Amortization Period, maximum		2 years
State Commission Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0.0	0.0
Regulatory Asset, Noncurrent		$ 3.4	3.5
Regulatory asset, remaining amortization period		Plant lives
Renewable Resources and Environmental Initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 39.2	45.9
Regulatory Asset, Noncurrent		$ 0.4	0.4
Regulatory Asset Amortization Period, minimum		1 year
Regulatory Asset Amortization Period, maximum		2 years
Gas Pipeline Inspection and Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 27.4	22.6
Regulatory Asset, Noncurrent		$ 0.0	4.5
Regulatory Asset Amortization Period, maximum		1 year
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 19.6	17.2
Regulatory Asset, Noncurrent		$ 20.5	$ 32.1
Regulatory asset, remaining amortization period		Various

[1] Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

[2] Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

[3] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 262.4	$ 83.4
Regulatory Liability, Noncurrent	[1]	1,984.7	1,978.5
Deferred income tax adjustments and TCJA refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	153.7	0.0
Regulatory Liability, Noncurrent	[2]	$ 1,465.1	1,516.1
Regulatory liability, remaining amortization period		Various
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0.0	0.0
Regulatory Liability, Noncurrent		$ 484.6	441.6
Regulatory liability, remaining amortization period		Plant lives
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[3]	$ 0.0	0.0
Regulatory Liability, Noncurrent	[3]	$ 8.9	9.5
Regulatory liability, remaining amortization period		Various
Deferred Electric Energy Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 22.8	11.3
Regulatory Liability, Noncurrent		$ 0.0	0.0
Regulatory liability remaining amortization period, maximum		1 year
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 13.0	12.8
Regulatory Liability, Noncurrent		$ 0.0	0.0
Regulatory liability remaining amortization period, maximum		1 year
Contract Valuation Adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[4]	$ 10.4	17.2
Regulatory Liability, Noncurrent	[4]	$ 0.0	0.0
Regulatory liability remaining amortization period, maximum		1 year
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 8.8	19.4
Regulatory Liability, Noncurrent		$ 0.0	0.0
Regulatory liability remaining amortization period, maximum		1 year
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 53.7	22.7
Regulatory Liability, Noncurrent		$ 26.1	11.3
Regulatory liability, remaining amortization period		Various
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		$ 12.5	$ 15.1

[1] Revenue subject for refund of $12.5 million and $15.1 million for 2018 and 2017, respectively, is included in other current liabilities.

[2] Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

[3] Includes impact of lower federal tax rate due to the TCJA.

[4] Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Short-term Debt [Line Items]
Short-term Debt	$ 150,000,000	$ 150,000,000	$ 20,000,000
Money Pool [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	250,000,000	250,000,000	250,000,000	$ 250,000,000
Short-term Debt	0	0	85,000,000	0
Short-term Debt, Average Outstanding Amount	18,000,000	17,000,000	25,000,000	16,000,000
Short-term Debt, Maximum Amount Outstanding During Period	$ 76,000,000	$ 143,000,000	$ 142,000,000	$ 225,000,000
Short-term Debt, Weighted Average Interest Rate, over Time	2.23%	1.96%	1.14%	0.69%
Short-term Debt, Weighted Average Interest Rate, at Point in Time			1.18%
Commercial Paper [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500,000,000	$ 500,000,000	$ 500,000,000	$ 500,000,000
Short-term Debt	150,000,000	150,000,000	20,000,000	85,000,000
Short-term Debt, Average Outstanding Amount	62,000,000	38,000,000	62,000,000	73,000,000
Short-term Debt, Maximum Amount Outstanding During Period	$ 198,000,000	$ 198,000,000	$ 237,000,000	$ 353,000,000
Short-term Debt, Weighted Average Interest Rate, over Time	2.53%	2.08%	1.10%	0.65%
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.97%	2.97%	1.93%	0.94%

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Short-term Debt	$ 150.0	$ 20.0
Letter of Credit
Line of Credit Facility [Line Items]
Short-term Debt	$ 37.0	$ 24.0
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Period	1 year

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Credit Facilities (Details) - Revolving Credit Facility [Member]		12 Months Ended
		Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)		48.00%	48.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions		$ 75,000,000
Line of Credit Facility, Maximum Borrowing Capacity	[1]	500,000,000
Drawn	[2]	187,000,000
Available		$ 313,000,000
Debt Instrument, Maturity Date		Jun. 30, 2021
Direct advances on the credit facility outstanding		$ 0	$ 0

[1] This credit facility matures in June 2021 .

[2] Includes outstanding commercial paper and letters of credit.

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Long-Term Borrowings and Other Financing Instruments
Unamortized discount	$ (21)	$ (22)
Unamortized debt expense	(42)	(45)
Less current maturities	0	0
Long-term debt, noncurrent	4,937	4,933
2019	0
2020	300
2021	0
2022	300
2023	400
First Mortgage Bonds
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross	$ 5,000	$ 5,000
Debt Instrument, Maturity Date Range, Start	Aug. 15, 2020
Debt Instrument, Maturity Date Range, End	Sep. 15, 2047
First Mortgage Bonds | Minimum
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage	2.15%	2.15%
First Mortgage Bonds | Maximum
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage	7.125%	7.125%
First Mortgage Bonds | Series Due Sept. 15, 2047 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 600
Debt Instrument, Interest Rate, Stated Percentage		3.60%
Debt Instrument, Maturity Date		Sep. 15, 2047
Revolving Credit Facility [Member]
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Maturity Date	Jun. 30, 2021

XML

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred Financing Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 42	$ 45

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Dividend and Other Capital-Related Restrictions (Details) $ in Billions	Dec. 31, 2018 USD ($)
Dividend and Other Capital-Related Restrictions [Abstract]
Equity to total capitalization ratio, low end of range (in hundredths)	47.10%
Equity to total capitalization ratio, high end of range (in hundredths)	57.50%
Equity to total capitalization ratio	52.30%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 1.0
Capitalization, Short term debt, long term debt and equity	10.7
Maximum total capitalization	$ 11.5

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Revenues Revenues (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 1,271,600	$ 1,351,800	$ 1,187,700	$ 1,310,800	$ 1,274,200	$ 1,355,800	$ 1,164,900	$ 1,307,100	$ 5,121,900	$ 5,102,000	$ 4,900,300
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,916,900
Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									3,975,900
Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									1,644,400
Retail | Commercial and Industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									2,291,600
Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									39,900
Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									189,200
Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									238,100
Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									473,700
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									40,000
Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Total operating revenues									205,000
Regulated Electric | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,326,300
Regulated Electric | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									3,397,000
Regulated Electric | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									1,308,400
Regulated Electric | Retail | Commercial and Industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									2,052,100
Regulated Electric | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									36,500
Regulated Electric | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									189,200
Regulated Electric | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									238,100
Regulated Electric | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									473,700
Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									28,300
Regulated Electric | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Total operating revenues									181,700
Regulated Natural Gas | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									559,800
Regulated Natural Gas | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									548,100
Regulated Natural Gas | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									308,800
Regulated Natural Gas | Retail | Commercial and Industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									239,300
Regulated Natural Gas | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
Regulated Natural Gas | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
Regulated Natural Gas | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
Regulated Natural Gas | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
Regulated Natural Gas | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									11,700
Regulated Natural Gas | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Total operating revenues									23,300
All Other | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									30,800
All Other | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									30,800
All Other | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									27,200
All Other | Retail | Commercial and Industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									200
All Other | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									3,400
All Other | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
All Other | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
All Other | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
All Other | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
All Other | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Total operating revenues									0
Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues									5,121,900
Operating Segments | Regulated Electric
Disaggregation of Revenue [Line Items]
Total operating revenues									4,508,000
Operating Segments | Regulated Natural Gas
Disaggregation of Revenue [Line Items]
Total operating revenues									583,100
Operating Segments | All Other
Disaggregation of Revenue [Line Items]
Total operating revenues									$ 30,800

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Income Taxes (Details) - USD ($)		1 Months Ended	3 Months Ended				12 Months Ended
		Dec. 31, 2017	Dec. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2015	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Corporate Federal Tax Rate		21.00%					21.00%
Tax Cuts and Jobs Act of 2017, Net Operating Loss Deduction Limitation, Percent of Taxable income							80.00%
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit, Gross								$ 1,500,000,000
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit)								19,000,000
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Net Income Reduction								5,000,000
Tax Audits [Abstract]
Unrecognized Tax Benefits, Interest on Income Taxes Accrued																$ (1,200,000)	$ (900,000)	$ (2,000,000)	$ (200,000)
Interest Income (Expense) related to unrecognized tax benefits							$ (300,000)	1,100,000		$ (1,800,000)
Number Of Years Of Tax Loss Carryback Period							two
Tax Adjustments, Settlements, and Unusual Provisions												$ 5,000,000	$ 17,000,000	$ 12,000,000	$ 15,000,000
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions																11,600,000	10,200,000
Unrecognized tax benefit — Temporary tax positions																5,300,000	7,900,000
Total unrecognized tax benefit		$ 18,100,000	$ 16,900,000				$ 18,100,000	60,800,000		55,400,000		55,400,000				16,900,000	18,100,000	60,800,000	$ 55,400,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1							18,100,000	60,800,000		55,400,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions							2,000,000	2,700,000		3,700,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions							(300,000)	(1,700,000)		(200,000)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions							600,000	5,700,000		3,900,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions							(1,100,000)	(49,400,000)		(2,000,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities							(2,400,000)	0		0
Balance at Dec. 31		$ 18,100,000	$ 16,900,000				$ 16,900,000	$ 18,100,000		$ 60,800,000		$ 55,400,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards																(12,700,000)	(12,800,000)
Net Deferred Tax Liability associated with the Unrecognized Tax Benefit Amounts and Related NOLs and Tax Credit Carryforwards																(7,300,000)	(5,700,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible																13,700,000
Amounts accrued for penalties related to unrecognized tax benefits																0	0	$ 0
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent							21.00%	35.00%	[1]	35.00%	[1]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent							7.10%	5.80%	[1]	5.80%	[1]
Effective Income Tax Rate Reconciliation, Tax Credit, Percent							(13.60%)	(11.40%)	[1]	(8.20%)	[1]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	[2]						(9.10%)	(0.10%)	[1]	(0.10%)	[1]
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items							(1.30%)	(1.00%)	[1]	(0.80%)	[1]
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent							0.30%	(0.20%)	[1]	(0.20%)	[1]
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits							0.10%	(1.60%)	[1]	0.20%	[1]
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent							0.00%	2.70%	[1]	0.00%	[1]
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent							0.70%	(0.20%)	[1]	(0.20%)	[1]
Effective Income Tax Rate Reconciliation, Percent							5.20%	29.00%	[1]	31.50%	[1]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)							$ (16,800,000)	$ 29,600,000		$ 19,300,000
Current State and Local Tax Expense (Benefit)							5,200,000	14,700,000		9,400,000
Current Change In Unrecognized Tax Expense (Benefit)							(1,100,000)	(36,200,000)		1,300,000
Deferred Federal Income Tax Expense (Benefit)							(2,400,000)	121,600,000		142,300,000
Deferred State and Local Income Tax Expense (Benefit)							42,100,000	46,700,000		53,800,000
Deferred Change In Unrecognized Tax Expense (Benefit)							1,600,000	24,900,000		100,000
Deferred investment tax credits							(1,400,000)	(1,600,000)		(1,700,000)
Income taxes							27,200,000	199,700,000		224,500,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items							70,100,000	(1,176,400,000)		225,100,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities							(28,200,000)	1,369,900,000		(28,700,000)
Other Comprehensive Income (Loss), Tax							(600,000)	(300,000)		(200,000)
Deferred Income Tax Expense (Benefit)							$ 41,300,000	193,200,000		$ 196,200,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment																2,257,600,000	2,253,200,000
Deferred Tax Liabilities, Regulatory Assets																263,100,000	222,700,000
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits																64,700,000	54,200,000
Deferred Tax Liabilities, Other																11,300,000	16,400,000
Deferred Tax Liabilities, Gross																2,596,700,000	2,546,500,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Regulatory Liabilities																382,800,000	386,600,000
Deferred Tax Assets Tax credit carryforward																467,300,000	392,400,000
Deferred Tax Assets, Operating Loss Carryforwards																17,900,000	153,500,000
Deferred Tax Assets, Valuation Allowance																(78,600,000)	(82,200,000)
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits																38,600,000	37,300,000
Deferred Tax Assets Deferred Investment Tax Credits																6,400,000	6,800,000
Deferred Tax Assets Rate Refund																49,700,000	6,600,000
Deferred Tax Assets, Other																30,200,000	33,200,000
Deferred Tax Assets, Net of Valuation Allowance																914,300,000	934,200,000
Deferred Tax Liabilities, Net																1,682,400,000	1,612,300,000
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Operating Loss Carryforwards																0	631,600,000
Tax Credit Carryforward, Amount																379,400,000	301,600,000
Carryforward expiration date range, low							2021
Carryforward expiration date range, high							2038
Tax years under examination, Concluded					2012 and 2013
Year(s) under examination			2014 - 2016			2012 and 2013									2010 and 2011
Year of carryback claim under examination															2009
Potential Tax Adjustments			$ 0
MINNESOTA
Tax Audits [Abstract]
Tax years under examination, Concluded			2010 - 2014
Earliest Open Tax Year Subject To Examination							2009
Potential Tax Adjustments				$ 0
State and Local Jurisdiction
Tax Audits [Abstract]
Operating Loss Carryforwards																221,200,000	275,500,000
Operating Loss Carryforwards, Valuation Allowance																(800,000)	(900,000)
Tax Credit Carryforward Net Of Federal Detriment	[3]															87,900,000	90,700,000
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit	[4]															(78,500,000)	(82,200,000)
Federal detriment																23,400,000	24,100,000
Federal Benefit																$ 20,900,000	$ 21,800,000
Carryforward expiration date range, low							2019
Carryforward expiration date range, high							2035
Plant Related Regulatory Liability [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit								1,100,000,000
Non-Plant Related Regulated Liability [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit								56,000,000
Non-Plant Related Regulatory Asset [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Asset, Provisional Income Tax Expense (Benefit)								$ 133,000,000

[1] (a) Prior periods have been reclassified to conform to current year presentation.

[2] (b) ARAM is a method to flow back excess deferred taxes to customers.

[3] State tax credit carryforwards are net of federal detriment of $23.4 million and $24.1 million as of Dec. 31, 2018 and 2017, respectively.

[4] Valuation allowances for state tax credit carryforwards were net of federal benefit of $20.9 million and $21.8 million as of Dec. 31, 2018 and 2017, respectively.

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Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Gross Unrealized Gain	$ 450.1	$ 559.9
Available-for-sale Securities, Gross Unrealized Loss	44.8	7.4
Investments [Abstract]
Miscellaneous investments	52.5	49.1
Decommissioning Fund Investments, Fair Value	2,054.7	2,143.3
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	24.3
Available-for-sale Securities	1,649.4	1,590.8
Debt Securities, Available-for-sale	465.6	437.7
Available-for-sale Securities, Equity Securities	401.4	423.1
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	758.1	701.3
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	24.3	28.7
Available-for-sale Securities		2,143.3
Alternative Investment	819.1	659.1
Debt Securities, Available-for-sale	435.6	441.6
Available-for-sale Securities, Equity Securities	696.5	791.1
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	0.0	0.0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	898.3	881.9
Alternative Investment	819.1	659.1
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	0.0	0.0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	0.0	0.0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	24.3
Available-for-sale Securities	800.0	1,042.6
Debt Securities, Available-for-sale	0.0	0.0
Available-for-sale Securities, Equity Securities	696.5	791.1
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	79.2	222.8
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0.0	0.0
Available-for-sale Securities	435.6	441.6
Debt Securities, Available-for-sale	435.6	441.6
Available-for-sale Securities, Equity Securities	0.0	0.0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	0.0	0.0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0.0	0.0
Available-for-sale Securities	0.0
Debt Securities, Available-for-sale	0.0	0.0
Available-for-sale Securities, Equity Securities	0.0	0.0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	$ 0.0	$ 0.0

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Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Rabbi Trust (Details) - Fair Value Measured on a Recurring Basis - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	$ 11.2	$ 11.1
Cost | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		0.4	0.8
Cost | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI		10.8	10.3
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	11.1	12.1
Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	11.1	12.1
Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	0.0	0.0
Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	0.0	0.0
Fair Value | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0.4	0.8
Fair Value | Rabbi Trust [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		0.4	0.8
Fair Value | Rabbi Trust [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		0.0	0.0
Fair Value | Rabbi Trust [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		0.0	0.0
Fair Value | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	10.7	11.3
Fair Value | Mutual Funds [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI		10.7	11.3
Fair Value | Mutual Funds [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI		0.0	0.0
Fair Value | Mutual Funds [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI		$ 0.0	$ 0.0

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

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Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Millions	Dec. 31, 2018 USD ($)
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	$ 10.6
Due in 1 to 5 Years	106.9
Due in 5 to 10 Years	210.5
Due after 10 Years	107.6
Total	$ 435.6

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Dec. 31, 2018 USD ($) MMBTU MWh Counterparty	Dec. 31, 2017 MMBTU MWh
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		10
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		7
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		6
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 35.9
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		44.00%
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		2
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 14.4
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		18.00%
Credit Concentration Risk | External Credit Rating, Non Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 1.3
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		2.00%
Credit Concentration Risk | Internal Noninvestment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 11.8
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		14.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $		$ (0.8)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional Amount | MWh	[1],[2]	56.8	41.7
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU	[1],[2]	42.7	23.8
Vehicle Fuel Commodity (in gallons)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU	[1],[2]	0.0	0.2

[1] Amounts are not reflective of net positions in the underlying commodities.

[2] Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

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Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1		$ (20.9)	$ (18.2)	$ (19.1)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		0.0	0.1	0.0
After-tax net realized losses on derivative transactions reclassified into earnings		0.7	0.9	0.9
Adoption of ASU. 2018-02 (a)	[1]	0.0	(3.7)	0.0
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		$ (20.2)	$ (20.9)	$ (18.2)

[1] In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges		$ 0.0	$ 0.0	$ 0.0
Designated as Hedging Instrument | Cash Flow Hedges
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss			0.1
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities			0.0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		1.0	1.5	1.5
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0.0	0.0	0.0
Derivative, Gain (Loss) on Derivative, Net		0.0	0.0	0.0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[1]	1.1	1.5	1.4
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0.0	0.0	0.0
Derivative, Gain (Loss) on Derivative, Net		0.0	0.0	0.0
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel And Other Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss			0.1
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities			0.0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[2]	(0.1)		0.1
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0.0		0.0
Derivative, Gain (Loss) on Derivative, Net		0.0		0.0
Other Derivative Instruments
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0.0	0.0	0.0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(3.7)	7.4	13.2
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0.0	0.0	0.0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		1.4	(12.8)	(2.1)
Derivative, Gain (Loss) on Derivative, Net		9.6	8.2	0.6
Other Derivative Instruments | Commodity Trading
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0.0	0.0	0.0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0.0	0.0	0.0
Derivative, Gain (Loss) on Derivative, Net	[3]	10.9	9.4	2.8
Other Derivative Instruments | Electric Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0.0	0.0	0.0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(5.5)	9.3	14.4
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0.0	0.0	0.0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	[4]	3.3	(13.8)	(6.1)
Derivative, Gain (Loss) on Derivative, Net		0.0	0.0	0.0
Other Derivative Instruments | Natural Gas Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0.0	0.0	0.0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		1.8	(1.9)	(1.2)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0.0	0.0	0.0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	[5]	(1.9)	1.0	4.0
Derivative, Gain (Loss) on Derivative, Net	[5]	$ (1.3)	$ (1.2)	$ (2.2)

[1] Amounts are recorded to interest charges.

[2] Amounts are recorded to O&M expenses.

[3] 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.

[4] 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.

[5] 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 and liabilities, as appropriate.

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Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 0.0	$ 0.0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0.0	$ 0.0

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		$ 31.5	$ 0.0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		8.7	3.1
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		25.8	25.2
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		17.0	28.1
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		16.5	17.7
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		112.2	102.7
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		25.8	24.6
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	(16.1)	(12.1)
Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.1
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	0.0	0.0
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14.4	7.2
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	(16.0)	(11.7)
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		10.4	17.2
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	(0.1)	(0.4)
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1.0	0.1
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	0.0	0.0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16.9	28.0
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	(13.4)	(6.5)
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16.9	28.0
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	(13.4)	(6.5)
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2.5	3.6
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]	(24.6)	(12.4)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2.5	3.6
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]	(24.5)	(12.0)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]	(0.1)	(0.4)
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		35.6	12.8
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]	17.9	(9.4)
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		35.6	12.8
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]	17.9	(9.4)
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1.1	1.7
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1.1	1.7
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1.4	1.7
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1.4	1.7
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.1	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.1	0.0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		28.1	17.3
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.1
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		27.1	17.1
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1.0	0.1
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		25.3	29.1
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		25.3	29.1
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		23.9	13.9
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		23.9	13.9
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		16.0	22.2
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		16.0	22.2
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		12.7	17.7
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		2.2	0.1
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		10.5	17.6
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5.0	5.4
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5.0	5.4
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1.8	0.4
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1.7	0.0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.1	0.4
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1.6	0.0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1.6	0.0
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[2]	0.0	0.6
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[2]	0.1	0.1
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]	14.0	14.1
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]	76.6	89.9
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		41.9	36.7
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.1
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		30.4	18.9
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		10.5	17.6
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1.0	0.1
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		30.3	34.5
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		30.3	34.5
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		27.1	16.0
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		27.0	15.6
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.1	0.4
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		17.7	22.2
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		$ 17.7	$ 22.2

[1] NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2018 and 2017. At Dec. 31, 2018 and 2017, derivative assets and liabilities include $31.5 million and $0 million of obligations to return cash collateral, respectively. At Dec. 31, 2018 and 2017, derivative assets and liabilities include the rights to reclaim cash collateral of $8.7 million and $3.1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[2] During 2006, 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.

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Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ 22.6	$ 15.3	$ 13.0
Purchases		26.4	40.6	28.0
Settlements		(17.2)	(41.7)	(47.2)
(Losses) gains recognized in earnings	[1]	(1.5)	5.5	0.0
Net gains (losses) recognized as regulatory assets and liabilities		(16.0)	2.9	21.5
Balance at end of period		14.3	22.6	15.3
Transfers into Level 3		0.0	0.0	0.0
Transfers out of Level 3		$ 0.0	$ 0.0	$ 0.0

[1] Amounts relate to commodity derivatives held at the end of the period.

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,937.2	$ 4,933.0
Estimate of Fair Value Measurement [Member]
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 5,230.9	$ 5,601.9

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Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		$ 4,000	$ 5,000
Net benefit cost recognized for financial reporting		1,000	1,000
Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		907,000	1,035,100	$ 1,036,500
Net benefit cost recognized for financial reporting		$ 26,200	$ 25,100	$ 29,600
Minimum number of years historical achieved weighted average annual returns used to determine investment return assumptions (in years)		20 years
Expected average long-term rate of return on assets (as a percent)		7.10%	7.10%	7.10%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		100.00%	100.00%
Pension Plan | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		37.00%	38.00%
Pension Plan | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		28.00%	23.00%
Pension Plan | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		18.00%	21.00%
Pension Plan | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		15.00%	16.00%
Pension Plan | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		2.00%	2.00%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		$ 33,000	$ 37,000
Net benefit cost recognized for financial reporting		$ 4,000	$ 5,000
Scenario, Forecast [Member] | Pension Plan
Pension Benefits [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)	7.10%

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Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plan - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 710.6	$ 824.5	$ 783.2
Plan assets at net asset value	263.0	302.5
Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	302.6	362.0
Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	145.0	160.0
Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	143.7	159.0
Plan assets at net asset value	0.0	0.0
Debt Securities [Member] | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Debt Securities [Member] | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	143.7	159.0
Debt Securities [Member] | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Cash
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	31.8	53.4
Plan assets at net asset value	0.0	0.0
Cash | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	31.8	53.4
Cash | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Cash | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Commingled Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	512.2	587.6
Plan assets at net asset value	271.2	302.4
Commingled Funds | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	241.0	285.2
Commingled Funds | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Commingled Funds | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Domestic and international equity securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	29.3	32.1
Plan assets at net asset value	0.0	0.0
Domestic and international equity securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	29.3	32.1
Domestic and international equity securities | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Domestic and international equity securities | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.0	0.0
Other
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	(6.4)	(7.6)
Plan assets at net asset value	(8.2)	0.1
Other | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0.5	(8.7)
Other | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	1.3	1.0
Other | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0.0	$ 0.0

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Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Millions		12 Months Ended
		Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) Plan	Dec. 31, 2017 USD ($) Plan	Dec. 31, 2016 USD ($) Plan
Significant Assumptions Used to Measure Costs [Abstract]
Liability, Defined Benefit Plan, Noncurrent			$ (305.1)	$ (331.1)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[1]		(48.8)	(48.2)	$ 0.0
Defined Benefit Plan, Accumulated Benefit Obligation			845.0	969.0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 907.0	1,035.1	1,036.5
Service cost			28.0	27.8	28.3
Interest cost			35.2	40.7	45.4
Plan amendments			0.0	(4.4)
Actuarial (gain) loss			(50.8)	64.1
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant			0.0	0.0
Medicare subsidy reimbursements			0.0	0.0
Benefit payments			(140.5)	(129.6)
Obligation at Dec. 31			907.0	1,035.1	1,036.5
Defined Benefit Plan, Plan Assets, Payment for Settlement			105.0
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		$ 710.6	824.5	783.2
Actual return (loss) on plan assets			(36.5)	110.1
Employer contributions			63.1	60.7
Benefit payments			(140.5)	(129.5)
Fair value of plan assets at Dec. 31			710.6	824.5	783.2
Funded Status of Plans at Dec. 31 [Abstract]
Funded status			(196.4)	(210.6)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			502.0	545.3
Prior service (credit) cost			(1.2)	(1.3)
Total			500.8	544.0
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets			35.5	37.7
Noncurrent regulatory assets			465.3	506.3
Total			$ 500.8	$ 544.0
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			4.31%	3.63%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%
Mortality table			RP-2014	RP-2014
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 63.0	$ 61.0	49.0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			28.0	27.8	28.3
Interest cost			35.2	40.7	45.4
Expected return on plan assets			(58.2)	(60.1)	(60.9)
Amortization of prior service cost (credit)			(0.1)	1.1	0.9
Amortization of net loss			38.5	39.6	36.8
Net periodic pension cost			92.2	97.3	50.5
Costs not recognized due to effects of regulation			(66.0)	(72.2)	(20.9)
Net benefit cost recognized for financial reporting			26.2	25.1	$ 29.6
Significant Assumptions Used to Measure Costs [Abstract]
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant			0.0	0.0
Liability, Defined Benefit Plan, Current			0.0	0.0
Liability, Defined Benefit Plan, Noncurrent			(196.4)	(210.6)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position			$ (196.4)	$ (210.6)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate			3.63%	4.13%	4.66%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase			3.75%	3.75%	4.00%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Deferred Income Taxes				$ 0.0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income				0.0
Defined Benefit Plan, Accumulated Benefit Obligation			$ (845.0)	$ (969.0)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets			7.10%	7.10%	7.10%
Xcel Energy Inc. | Pension Plan
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan			4	4	4
Total contributions to Xcel Energy's pension plans during the period			$ 150.0	$ 162.0	$ 125.0
Subsequent Event
Cash Flows [Abstract]
Number of pension plans to which contributions were made		4
Significant Assumptions Used to Measure Costs [Abstract]
Expected contribution to postretirement health care plans next year		$ 7.0
Subsequent Event | Pension Plan
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		47.0
Subsequent Event | Xcel Energy Inc.
Significant Assumptions Used to Measure Costs [Abstract]
Expected contribution to postretirement health care plans next year		11.0
Subsequent Event | Xcel Energy Inc. | Pension Plan
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 150.0

[1] A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of $48.8 million in 2018 and $48.2 million in 2017,

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Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 12	$ 12	$ 12

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Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Postretirement Benefits Plan	Dec. 31, 2018	Dec. 31, 2017
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	18.00%	24.00%
Long-duration fixed income and interest rate swap securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	0.00%	0.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	70.00%	60.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	8.00%	9.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	4.00%	7.00%

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Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefits Plan - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 2.4	$ 6.5	$ 3.7
Plan assets at net asset value	0.2	0.0
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.9	3.0
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1.3	3.5
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Debt Securities [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1.0	2.8
Plan assets at net asset value	0.0	0.0
Debt Securities [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Debt Securities [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1.0	2.8
Debt Securities [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Equity Securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.5
Plan assets at net asset value	0.0	0.0
Equity Securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.5
Equity Securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Equity Securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Cash
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.1	0.4
Plan assets at net asset value	0.0	0.0
Cash | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.1	0.4
Cash | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Cash | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.3	0.7
Plan assets at net asset value	0.0	0.0
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.3	0.7
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Commingled Funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1.0	2.1
Plan assets at net asset value	0.2	0.0
Commingled Funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.8	2.1
Commingled Funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Commingled Funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Plan assets at net asset value	0.0	0.0
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0.0	$ 0.0

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Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities		$ (305.1)	$ (331.1)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		3.0	10.0	$ 9.0
Postretirement Benefits Plan
Defined Benefit Plan Disclosure [Line Items]
Plan amendments		0.0	0.0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets			0.0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 76.0	88.8	86.7
Service cost		0.2	0.1	0.1
Interest cost		3.1	3.4	3.9
Medicare subsidy reimbursements		0.0	0.0
Plan participants' contributions		0.4	0.4
Actuarial (gain) loss		(9.0)	5.9
Benefit payments		(7.5)	(7.7)
Obligation at Dec. 31		76.0	88.8	86.7
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	2.4	6.5	3.7
Actual return (loss) on plan assets		0.0	0.0
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		0.4	0.4
Employer contributions		3.0	10.1
Benefit payments		(7.5)	(7.7)
Fair value of plan assets at Dec. 31		2.4	6.5	3.7
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(73.6)	(82.3)
Current liabilities		(4.8)	(1.3)
Noncurrent liabilities		(68.8)	(81.0)
Net postretirement amounts recognized on consolidated balance sheets		(73.6)	(82.3)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		34.3	45.3
Prior service (credit) cost		(12.4)	(15.4)
Total		21.9	29.9
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Noncurrent regulatory assets		20.5	28.0
Deferred income taxes		0.4	0.5
Net-of-tax accumulated other comprehensive income		1.0	1.4
Total		$ 21.9	$ 29.9
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		4.32%	3.62%
Mortality table		RP-2014	RP-2014
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		6.50%	7.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		5.30%	5.50%
Ultimate health care trend assumption rate (as a percent)		4.50%	4.50%
Period until ultimate trend rate is reached (in years)		4	5
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 0.2	$ 0.1	0.1
Interest cost		3.1	3.4	3.9
Expected return on plan assets		(0.4)	(0.2)	(0.2)
Amortization of prior service cost (credit)		(3.0)	(3.0)	(3.0)
Amortization of net loss		2.4	2.0	1.6
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0.0	0.0	0.0
Net periodic postretirement benefit cost		$ 2.3	$ 2.3	$ 2.4
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		3.62%	4.13%	4.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		0.00%	0.00%	0.00%
Expected average long-term rate of return on assets (as a percent)		5.30%	5.80%	5.80%
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation		$ 0.0	$ 0.0	$ 0.0
Net benefit cost recognized for financial reporting		2.3	2.3	2.4
Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		$ 11.0	$ 20.0	$ 18.0
Subsequent Event
Cash Flows [Abstract]
Expected contribution to postretirement health care plans next year	7.0
Subsequent Event | Xcel Energy Inc.
Cash Flows [Abstract]
Expected contribution to postretirement health care plans next year	$ 11.0

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Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Millions	Dec. 31, 2018 USD ($)
Pension Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2019	$ 93.4
2020	81.2
2021	80.1
2022	79.0
2023	77.2
2024-2028	342.3
Postretirement Benefits Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2019	7.2
2020	7.0
2021	6.7
2022	6.3
2023	6.0
2024-2028	26.0
Expected Medicare Part D Subsidies [Abstract]
2019	0.0
2020	0.0
2021	0.0
2022	0.0
2023	0.0
2024-2028	0.0
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2019	7.2
2020	7.0
2021	6.7
2022	6.3
2023	6.0
2024-2028	$ 26.0

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Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Purchase Power Agreement Expiration	2039
Coal
Fuel Contracts [Abstract]
2019	$ 194.7
2020	87.4
2021	52.0
2022	34.7
2023	35.1
Thereafter	3.5
Total	407.4
Nuclear Fuel
Fuel Contracts [Abstract]
2019	127.1
2020	50.9
2021	99.0
2022	78.5
2023	99.4
Thereafter	337.1
Total	792.0
Natural Gas Supply
Fuel Contracts [Abstract]
2019	43.6
2020	1.4
2021	1.4
2022	0.8
2023	0.0
Thereafter	0.0
Total	47.2
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2019	107.4
2020	97.5
2021	95.6
2022	92.6
2023	82.8
Thereafter	320.7
Total	$ 796.6
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2019
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2037

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Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-term Contract for Purchase of Electric Power [Line Items]
Purchase Power Agreement Expiration	2039
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity	$ 52.7	$ 84.1	$ 89.8
Estimated Future Payments Under PPAs [Abstract]
2019	54.0
2020	54.6
2021	62.2
2022	61.3
2023	62.7
Thereafter	109.5
Total	404.3
Energy
Estimated Future Payments Under PPAs [Abstract]
2019	98.7
2020	109.4
2021	157.4
2022	172.9
2023	176.9
Thereafter	328.1
Total	$ 1,043.4

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Commitments and Contingencies, Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Leased Assets [Line Items]
Operating Lease Purchase Power Agreement Expiration Date	2026
Operating Leases, Future Minimum Payments Due [Abstract]
2019	$ 78.5
2020	74.5
2021	75.5
2022	76.3
2023	76.6
Thereafter	179.5
Office Space and Other Equipment
Operating Leases [Abstract]
Total expenses under operating lease obligations	76.2	$ 76.9	$ 79.1
Operating Leases, Future Minimum Payments Due [Abstract]
2019	13.5
2020	8.4
2021	8.4
2022	8.1
2023	7.3
Thereafter	36.0
Purchased Power Agreements
Operating Leases [Abstract]
Payments for capacity for PPAs under operating lease obligations	62.5	$ 62.7	$ 63.4
Operating Leases, Future Minimum Payments Due [Abstract]
2019	65.0
2020	66.1
2021	67.1
2022	68.2
2023	69.3
Thereafter	$ 143.5

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Commitments and Contingencies, Variable Interest Entities (Details) - Independent Power Producing Entities - MW	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,002	1,069
VIE Purchase Power Agreement Expiration Date	2027

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Commitments and Contingencies Commitments and Contingencies, Guarantees and Indemnifications (Details) - Performance Guarantee [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Obligations Under Railcar Leases
Guarantor Obligations [Line Items]
Guarantees issued and outstanding	$ 4.8
Current exposure under these guarantees	$ 0.0
Maximum
Guarantor Obligations [Line Items]
Guarantee Expiration Date (year)	2019

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Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	Dec. 31, 2018 USD ($) Site Plant	Dec. 31, 2017 USD ($)
Federal Coal Ash Regulation
Environmental Requirements [Abstract]
Number of regulated ash units that will still be in operation by the end of 2019	3
Number of impoundments where closure plans will be expedited	1
Estimated cost of construction of a new impoundment	$ 6.0
Clean Water Act Effluent Limitations Guidelines [Domain]
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation	$ 10.0
Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Minimum number of plants which could be required to make improvements to reduce entrainment | Plant	6
Capital Commitments | Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation	$ 39.0
Liability for estimated cost to comply with entrainment regulation	$ 194.0
Other MGP, Landfill, or Disposal Sites [Domain]
Site Contingency [Line Items]
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation | Site	6
Liability for estimated cost of remediating sites	$ 6.0	$ 19.0

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Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	[1]	$ 6,600		$ 5,500
Asset Retirement Obligation, Liabilities Incurred	[1]	0		0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		2,083,900	[2]	2,452,600
Liabilities settled	[1]	0		0
Accretion		103,200		122,000
Cash flow revisions	[3]	(2,600)		(485,200)
Ending balance	[2]	2,177,900		2,083,900
Legally restricted assets, for purposes of funding future nuclear decommissioning		2,054,700		2,143,300
Electric Plant Nuclear Production Decommissioning
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled		0		0
Asset Retirement Obligation, Liabilities Incurred		0		0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1,873,600	[2]	2,249,300
Liabilities settled		0		0
Accretion		94,700		113,800
Cash flow revisions		0		(489,500)
Ending balance	[2]	1,968,300		1,873,600
Electric Plant Steam Production Ash Containment
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled		6,600		4,900
Asset Retirement Obligation, Liabilities Incurred		0		0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		64,000	[2]	68,500
Liabilities settled		0		0
Accretion		2,100		2,400
Cash flow revisions		(10,300)		(2,000)
Ending balance	[2]	49,200		64,000
Electric Plant Wind Production
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled		0		0
Asset Retirement Obligation, Liabilities Incurred		0		0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		94,100	[2]	90,100
Liabilities settled		0		0
Accretion		4,300		4,000
Cash flow revisions		6,500		0
Ending balance	[2]	104,900		94,100
Electric Plant Electric Distribution
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled		0		0
Asset Retirement Obligation, Liabilities Incurred		0		0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		5,800	[2]	5,600
Liabilities settled		0		0
Accretion		200		200
Cash flow revisions		8,500		0
Ending balance	[2]	14,500		5,800
Electric Plant Other
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled		0		0
Asset Retirement Obligation, Liabilities Incurred		0		0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1,900	[2]	1,800
Liabilities settled		0		0
Accretion		0		100
Cash flow revisions		(100)		0
Ending balance	[2]	1,800		1,900
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled		0		0
Asset Retirement Obligation, Liabilities Incurred		0		0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		43,600	[2]	35,800
Liabilities settled		0		0
Accretion		1,800		1,500
Cash flow revisions		(7,200)		6,300
Ending balance	[2]	38,200		43,600
Natural Gas Plant Other
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled		0		0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		200		200
Accretion		0		0
Cash flow revisions		0		0
Ending balance		200		200
Common and Other Property Common Miscellaneous
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled		0		600
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		700	[2]	1,300
Accretion		100		0
Cash flow revisions		0		0
Ending balance	[2]	$ 800		$ 700

[1] Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

[2] amounts incurred in 2018.

[3] In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.

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Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 485	$ 442

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Commitments and Contingencies, Nuclear Insurance (Details) - Nuclear Insurance $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) Plant Reactor
Nuclear Insurance [Abstract]
Nuclear insurance coverage secured for the Company's public liability exposure	$ 450.0
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program	13,600.0
Maximum assessments per reactor per accident	$ 137.6
Number of owned and licensed reactors | Reactor	3
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	$ 2,300.0
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 18.0
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	39.0
Maximum
Nuclear Insurance [Abstract]
Loss Contingency, Estimate of Possible Loss	14,100.0
NSP Minnesota
Nuclear Insurance [Abstract]
Maximum funding requirement per reactor for any one year	$ 20.5

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Commitments and Contingencies, Legal Contingencies (Details) - USD ($) $ in Millions	1 Months Ended					12 Months Ended
	Jan. 31, 2019	Sep. 30, 2016	Dec. 31, 2015	Feb. 28, 2015	Nov. 30, 2013	Dec. 31, 2018	Dec. 31, 2017
General Electric (GE) [Domain]
Loss Contingencies [Line Items]
Percentage of Fault						52.00%
NSP Minnesota
Loss Contingencies [Line Items]
Percentage of Fault						48.00%
FERC Proceeding, MISO ROE Complaint [Member] | NSP Minnesota
Loss Contingencies [Line Items]
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates				12.38%	12.38%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties				8.67%	9.15%
Legal Contingencies [Abstract]
Public Utilities, ROE developed with new approach						10.28%
Public Utilities, Number of steps required						2
Federal Energy Regulatory Commission (FERC) [Member] | FERC Proceeding, MISO ROE Complaint [Member] | NSP Minnesota
Legal Contingencies [Abstract]
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved		10.32%	10.32%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved							10.82%
Subsequent Event | NSP Minnesota
Legal Contingencies [Abstract]
Customer refund of previously recovered purchased power costs	$ 20.0

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Commitments and Contingencies Nuclear Obligations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) Canister		Dec. 31, 2017 USD ($)		Dec. 31, 2016 USD ($)
Fuel Disposal [Abstract]
DOE fuel disposal assessments included in fuel expense			$ 0.0
Regulatory Plant Decommissioning Recovery [Abstract]
Assumed annual escalation rate during plant removal activities	4.36%		4.36%
Assumed annual escalation rate during spent fuel management and site restoration activities	3.36%		3.36%
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds	100.00%
Approved annual accrual for decommissioning costs	$ 14.0		$ 0.0		$ 0.0
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)	3,012.3		3,012.3
Effect of escalating costs (to 2018 and 2017 dollars, respectively, at 4.36/3.36%)	538.9		395.7
Estimated decommissioning cost obligation (in current dollars)	3,551.2		3,408.0
Effect of escalating costs to payment date (4.36/3.36%)	7,654.3		7,797.5
Estimated future decommissioning costs (undiscounted)	11,205.5		11,205.5
Effect of discounting obligation (using average risk-free interest rate of 3.33% and 2.80% for 2018 and 2017, respectively)	(6,911.5)		(6,398.1)
Discounted decommissioning cost obligation	4,294.0		4,807.4
Decommissioning Fund Investments, Fair Value	2,054.7		2,143.3
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation	(2,239.3)		(2,664.1)
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Differences in Discount Rate and Market Risk Premium	(1,446.4)		(1,402.8)
Operating and Maintenance Costs Not Included for GAAP	(879.3)		(1,041.5)
Differences in Cost Studies	0.0		(489.5)
Asset Retirement Obligation	2,177.9	[1]	2,083.9	[1]	2,452.6
Annual Decommissioning Recorded As Depreciation Expense [Abstract]
Annual decommissioning recorded as depreciation expense	$ 20.4		20.4		20.4
Minimum
Regulatory Plant Decommissioning Recovery [Abstract]
Assumed after tax rate of return used to determine funding for external decommissioning trust fund	5.23%
Maximum
Regulatory Plant Decommissioning Recovery [Abstract]
Assumed after tax rate of return used to determine funding for external decommissioning trust fund	6.30%
Nuclear Plant
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Asset Retirement Obligation	$ 1,968.3	[1]	1,873.6	[1]	$ 2,249.3
Monticello [Member]
Fuel Disposal [Abstract]
Number of authorized canisters filled and placed in dry cask nuclear storage facility | Canister	30
Prairie Island [Member]
Fuel Disposal [Abstract]
Number of authorized canisters filled and placed in dry cask nuclear storage facility | Canister	44
Number of authorized canisters in dry cask nuclear storage facility | Canister	64
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Available-for-sale Securities			$ 2,143.3
Measurement Input, Risk Free Interest Rate [Member]
Public Utilities, General Disclosures [Line Items]
Debt Instrument, Measurement Input	0.0333		0.028

[1] amounts incurred in 2018.

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Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 0	$ 0	$ 0
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	0	0	0
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	5,475,600
Other comprehensive income (loss) before reclassifications	500	(400)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	200	100
Accumulated other comprehensive (loss) income at end of period	5,573,100	5,475,600
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	300	(400)	(500)
Income tax expense (benefit)	27,200	199,700	224,500
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(20,900)	(18,200)
Other comprehensive income (loss) before reclassifications	0	100
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0
Net current period other comprehensive income (loss)	700	1,000
Adoption of ASU No. 2018-02 (a)		(3,700)
Accumulated other comprehensive (loss) income at end of period	(20,200)	(20,900)	(18,200)
Unrealized Gains and Losses on Marketable Securities
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	100	100
Other comprehensive income (loss) before reclassifications	(100)	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0
Net current period other comprehensive income (loss)	(100)	0
Adoption of ASU No. 2018-02 (a)		0
Accumulated other comprehensive (loss) income at end of period	0	100	100
Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(3,700)	(2,700)
Other comprehensive income (loss) before reclassifications	600	(500)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	200	100
Net current period other comprehensive income (loss)	800	(400)
Adoption of ASU No. 2018-02 (a)		(600)
Accumulated other comprehensive (loss) income at end of period	(2,900)	(3,700)	(2,700)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	300	100
Reclassification from AOCI, Current Period, Tax	100	100
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive (loss) income at beginning of period	(24,500)	(20,800)
Net current period other comprehensive income (loss)	1,400	600
Adoption of ASU No. 2018-02 (a)		(4,300)
Accumulated other comprehensive (loss) income at end of period	(23,100)	(24,500)	$ (20,800)
Amounts Reclassified from Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	0	0
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Income tax expense (benefit)	0	0
Reclassification from AOCI, Current Period, Tax	0	0
Amounts Reclassified from Accumulated Other Comprehensive Loss | Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax	0	0
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Income tax expense (benefit)	300	600
Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	700	900
Interest Rate Swap | Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	700	900
Interest Rate Swap | Unrealized Gains and Losses on Marketable Securities
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0
Interest Rate Swap | Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ 0	$ 0

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Segments and Related Information (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										$ 5,121.9	$ 5,102.0	$ 4,900.3
Intercompany revenue										473.7	490.2	475.5
Depreciation and amortization										741.6	700.6	596.7
Total interest charges and financing costs										214.3	213.3	214.0
Income tax expense (benefit)										27.2	199.7	224.5
Net income (loss)		$ 87.0	$ 201.2	$ 92.4	$ 111.7	$ 79.3	$ 229.0	$ 87.7	$ 94.2	492.3	490.1	488.7
Regulated Electric
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										4,508.8	4,542.4	4,405.2
Depreciation and amortization										697.8	661.3	554.3
Total interest charges and financing costs										199.5	199.8	200.8
Income tax expense (benefit)										16.4	179.9	215.5
Net income (loss)										450.4	462.5	465.4
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										583.6	532.4	467.9
Depreciation and amortization										43.3	38.7	41.8
Total interest charges and financing costs										14.8	13.5	13.2
Income tax expense (benefit)										10.2	10.0	12.0
Net income (loss)										34.2	28.4	18.3
All Other
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]									30.8	28.3	28.3
Depreciation and amortization										0.5	0.6	0.6
Total interest charges and financing costs										0.0	0.0	0.0
Income tax expense (benefit)										0.6	9.8	(3.0)
Net income (loss)										7.7	(0.8)	5.0
Operating Segments
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										5,123.2	5,103.1	4,901.4
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]									4,508.0	4,541.8	4,404.6
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]									583.1	531.9	467.4
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										(1.3)	(1.1)	(1.1)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										0.8	0.6	0.6
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										$ 0.5	$ 0.5	$ 0.5

[1] (a) Operating revenues include $473.7 million, $490.2 million, and $475.5 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 13 for further information.

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Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Revenues	$ 1,271,600	$ 1,351,800	$ 1,187,700	$ 1,310,800	$ 1,274,200	$ 1,355,800	$ 1,164,900	$ 1,307,100	$ 5,121,900	$ 5,102,000	$ 4,900,300
Operating revenues
Related Party Transaction, Electric Domestic Regulated Revenue										490,200	475,500
Operating expenses
Purchased power									61,100	66,800	63,000
Transmission expense									96,800	110,500	107,500
Other operating expenses - paid to Xcel Energy Services Inc.									534,800	539,400	513,000
Interest expense									300	0	0
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	11,000				48,500				11,000	48,500
Accounts payable	109,700				80,100				109,700	80,100
Related Party Transaction, Electric Domestic Regulated Revenue										490,200	475,500
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	11,000				17,800				11,000	17,800
Accounts payable	0				0				0	0
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0				0				0	0
Accounts payable	17,900				7,700				17,900	7,700
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0				0				0	0
Accounts payable	4,700				1,000				4,700	1,000
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0				30,700				0	30,700
Accounts payable	$ 87,100				$ 71,400				87,100	71,400
Related Party Transaction, Electric Domestic Regulated Revenue [Member]
Related Party Transaction [Line Items]
Revenues									$ 473,700	$ 490,200	$ 475,500

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Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 1,271,600		$ 1,351,800		$ 1,187,700		$ 1,310,800		$ 1,274,200		$ 1,355,800		$ 1,164,900		$ 1,307,100		$ 5,121,900	$ 5,102,000	$ 4,900,300
Net income	135,500	[1]	259,500	[1]	150,100	[1]	171,400	[1]	187,400	[1]	339,700	[1]	173,100	[1]	182,500	[1]	716,500	882,700	912,100
Net income	$ 87,000		$ 201,200		$ 92,400		$ 111,700		$ 79,300		$ 229,000		$ 87,700		$ 94,200		$ 492,300	$ 490,100	$ 488,700

[1] (a) In 2018, NSP-Minnesota implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income

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Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1	$ 21.3	$ 20.0	$ 20.8
Charged to costs and expenses	16.2	15.7	15.0
Charged to other accounts	4.1	3.8	4.2
Deductions from reserves	(18.1)	(18.2)	(20.0)
Balance at Dec. 31	$ 23.5	$ 21.3	$ 20.0