ThZeal - The Zeal

nspm-20241231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2024 or


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

For the transition period from _____ to _____


001-31387
(Commission File Number)


Northern States Power Company
(Exact name of registrant as specified in its charter)

Minnesota

41-1967505

(State or Other Jurisdiction of Incorporation or Organization)

(IRS Employer Identification No.)

414 Nicollet Mall

Minneapolis

Minnesota

55401

(Address of Principal Executive Offices)

(Zip Code)


(612)			330-5500
(Registrant’s Telephone Number, Including Area Code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

N/A

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. ☒ 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 ☒ 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. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of 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). ☒ Yes ☐ No

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 ☒ 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

As of Feb. 27, 2025, 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 2025 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 8, 2025. 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


PART I
Item 1 —	Business	3
Item 1A —	Risk Factors	8
Item 1B —	Unresolved Staff Comments	15
Item 1C —	Cybersecurity	15
Item 2 —	Properties	16
Item 3 —	Legal Proceedings	17
Item 4 —	Mine Safety Disclosures	17

PART II
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6 —	[Reserved]	17
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	21
Item 8 —	Financial Statements and Supplementary Data	23
Item 9 —	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	54
Item 9A —	Controls and Procedures	54
Item 9B —	Other Information	55
Item 9C —	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	55

PART III
Item 10 —	Directors, Executive Officers and Corporate Governance	55
Item 11 —	Executive Compensation	55
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	55
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	55
Item 14 —	Principal Accountant Fees and Services	55

PART IV
Item 15 —	Exhibit s and Financial Statement Schedules	55
Item 16 —	Form 10-K Summary	57

Signatures		58

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.

Table of Contents

PART I


Item l — Business

Definitions of Abbreviations


Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
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
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
PHMSA			Pipeline and Hazardous Materials Safety Administration
SDPUC			South Dakota Public Utility Commission
SEC			Securities and Exchange Commission


Electric, Purchased Gas and Resource Adjustment Clauses
CIP			Conservation improvement program
DSM			Demand side management

RES			Renewable energy standard


Other
AFUDC			Allowance for funds used during construction
ALJ			Administrative law judge
ARO			Asset retirement obligation
ASC			Financial Accounting Standards Board Accounting Standards Codification
ASU			Accounting standards update
C&I			Commercial and industrial
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
CCR Rule			Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CEO			Chief executive officer
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFO			Chief financial officer
CON			Certificate of need
CO2			Carbon dioxide


CWIP			Construction work in progress



EMANI			European Mutual Association for Nuclear Insurance
ETR			Effective tax rate

FTR			Financial transmission right
GAAP			Generally accepted accounting principles
GE			General Electric
GHG			Greenhouse gas
INPO			Institute of Nuclear Power Operations
IPP			Independent power producing entity
ISO			Independent system operator
ITC			Investment tax credit

MGP			Manufactured gas plant
MISO			Midcontinent Independent System Operator, Inc.

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.
NOL			Net operating loss

O&M			Operating and maintenance
ONES			Operations, Nuclear, Environmental and Safety

PFAS			Per- and polyfluoroalkyl substances
Post-65			Post-Medicare
PPA			Purchased power agreement
Pre-65			Pre-Medicare
PTC			Production tax credit
RDF			Refuse-derived fuel
REC			Renewable energy credit
RFP			Request for proposal
ROE			Return on equity
ROU			Right-of-use
RTO			Regional transmission organization
S&P			Standard & Poor’s Global Ratings
SERP			Supplemental executive retirement plan
TCJA			2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
VaR			Value at risk
VIE			Variable interest entity


Measurements
Bcf			Billion cubic feet
KV			Kilovolts
KWh			Kilowatt hours
MMBtu			Million British thermal units
MW			Megawatts
MWh			Megawatt hours


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 through its website, free of charge, 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. The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K.

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, expected pension contributions and expected impact on our results of operations, financial condition and cash flows of interest rate changes, increased credit exposure and legal proceeding outcomes, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “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, 2024 (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), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of NSP-Minnesota 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; uncertainty regarding epidemics; effects of geopolitical events, including war and acts of terrorism; cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.


Company Overview

Electric customers

1.6 million

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. NSP-Minnesota and NSP-Wisconsin electric operations are 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.

Natural gas customers

0.6 million

Total assets

$27.5 billion

Rate Base (estimated)

$17.4 billion

GAAP ROE

9.07%

Ongoing ROE

9.46%

Electric generating capacity (owned)

8,623 MW

Gas storage capacity

16.9 Bcf

Electric transmission lines (conductor miles)

34,000 miles

Electric distribution lines (conductor miles)

87,000 miles

Natural gas transmission lines

78 miles

Natural gas distribution lines

11,000 miles


Electric Operations

Electric operations consist of energy supply, generation, transmission and distribution activities. NSP-Minnesota had electric sales volume of 42,700 (millions of KWh), 1.6 million customers and electric revenues of $5,099 million for 2024.


Electric Operations (percentage of total)	Sales Volume		Number of Customers		Revenues
Residential	24	%	89	%	29	%
C&I	51		10		43
Other	25		1		28

Retail Sales/Revenue Statistics (a)


	2024			2023
KWH sales per retail customer	20,220			21,127
Revenue per retail customer	$	2,348		$	2,461
Residential revenue per KWh	14.62		¢	14.28		¢
C&I revenue per KWh	10.12		¢	10.34		¢
Total retail revenue per KWh	11.61		¢	11.65		¢

(a) See Note 6 to the consolidated financial statements for further information.

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Owned and Purchased Energy Generation — 2024

Electric Energy Sources - NSP System

Total electric energy generation by source for the year ended Dec. 31:

Carbon–Free

The NSP System’s carbon–free energy portfolio includes nuclear, wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. Carbon–free percentages will vary year over year based on system additions, commodity costs, weather, system demand and transmission constraints.

See Item 2 — Properties for further information.

Wind

Wind capacity is shown as net maximum capacity. Net maximum capacity is attainable only when wind conditions are sufficiently available.

Owned — Owned and operated wind farms with corresponding capacity:


2024		2023
Wind Farms	Capacity (MW)	Wind Farms	Capacity (MW)
17	2,445	17	2,444

PPAs — Number of PPAs with capacity range:


2024		2023
PPAs	Range (MW)	PPAs	Range (MW)
116	1 — 206	120	1 — 206

Current contracted wind capacity for PPAs was 2,061 MW and 2,066 MW in 2024 and 2023, respectively.

In 2024, the average cost of wind energy was $7 per MWh for owned generation and $32 per MWh under existing PPAs. In 2023, the average cost of wind energy was $7 per MWh for owned generation and $33 per MWh under existing PPAs. The cost of owned wind includes the impact of PTCs.

The NSP System currently has 350 MW of approved owned wind repowering projects under development, estimated to be completed in 2025.

Additionally, the NSP System anticipates 3,200 MW to be placed in service by 2030, as part of the recently approved Upper Midwest Resource Plan. The RFP process will start in 2025.

Solar

Owned — Owned and operated solar projects with corresponding capacity:


2024		2023
Solar Projects (a)	Capacity (MW)	Solar Projects	Capacity (MW)
1	223	—	—

(a)NSP-Minnesota placed in service Sherco Solar 1 in the fourth quarter of 2024. Average cost per MWh will be available after a full year of operations.

PPAs — Solar PPAs capacity by type:


Type						Capacity (MW)
Distributed Generation						1,461
Utility-Scale						349
Total						1,810

The average cost of solar energy under existing distributed and utility-scale generation PPAs was $100 per MWh and $90 per MWh in 2024 and 2023, respectively.

Solar Development — The NSP System currently has 500 MW of owned solar approved at the Sherco site, which are expected to be placed in service in 2025 and 2026. Additionally, various PPAs totaling approximately 105 MW are expected to be completed throughout 2025. Incremental to this amount is 400 MW anticipated as part of the Upper Midwest Resource Plan, to be placed in service by 2030.

Nuclear

The NSP System has two nuclear plants (owned by NSP-Minnesota) with approximately 1,700 MW of total 2024 net summer dependable capacity that safely and reliably generates carbon free electricity. NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. NSP-Minnesota uses varying contract lengths as well as multiple producers for uranium concentrates, conversion services and enrichment services to minimize potential impacts caused by supply interruptions due to geographical and world political issues.

Nuclear Fuel Cost — Delivered cost per MMBtu of nuclear fuel consumed for owned electric generation and the percentage of total fuel requirements (nuclear, natural gas and coal):


	Nuclear
	Cost		Percent
2024	$	0.83	43	%
2023	0.76		50

Other

The NSP System’s other carbon-free energy portfolio includes hydro from owned generating facilities.

The NSP System anticipates development of approximately 300 MW of storage capacity at the Sherco site, expected to be placed in service in 2027. Additionally, 600 MW of stand-alone storage are expected to be added as part of the Upper Midwest Resource Plan, to be placed in service by 2030.

See Item 2 — Properties for further information.

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Fossil Fuel

The NSP System’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.

See Item 2 — Properties for further information.

Coal

The NSP System owns and operates coal units with approximately 1,700 MW of total capacity, which provided 10% of NSP System’s energy mix in 2024. All of these units are approved for retirement by 2030.

Approved early coal plant retirements:


Year	Plant Unit	Capacity (MW)
2026	Sherco 1	680
2028	A.S. King	511
2030	Sherco 3	517	(a)

(a)Based on the NSP System’s ownership interest.

Coal Fuel Cost — Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements (nuclear, natural gas and coal):


	Coal (a)
	Cost		Percent

2024	$	2.24	22	%
2023	2.43		29

(a)Includes RDF and wood.

Natural Gas

The NSP System has seven natural gas plants with approximately 2,800 MW of total capacity, which provided 26% of NSP System’s energy mix in 2024.

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.

Natural Gas Cost — Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements (nuclear, natural gas and coal):


	Natural Gas
	Cost	Percent
2024	1.94	35	%
2023	3.91	21

The NSP System anticipates the development of 700 MW of company owned natural gas generation expected to be placed in service between 2025 - 2028.

Capacity and Demand

Uninterrupted system peak demand and occurrence date:


2024		2023
MW	Date	MW	Date
8,822	Aug. 26	9,231	Aug. 23

Transmission

Transmission lines deliver electricity over long distances from power sources to substations closer to customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. NSP-Minnesota owns more than 33,000 conductor miles of transmission lines across the NSP System service territory.

See Item 2 - Properties for further information.

Distribution

Distribution lines allow electricity to travel at lower voltages from substations directly to customers. NSP-Minnesota has a vast distribution network, owning and operating approximately 87,000 conductor miles of distribution lines across our service territory.

See Item 2 - Properties for further information.


Natural Gas Operations

Natural gas operations consist of purchase, transportation and distribution of natural gas to end-use residential, C&I and transport customers. NSP-Minnesota had natural gas deliveries of 88,788 (thousands of MMBtu), 0.6 million customers and natural gas revenues of $653 million for 2024.


Natural Gas (percentage of total)	Deliveries		Number of Customers		Revenues
Residential	42	%	92	%	50	%
C&I	44		8		34
Transportation and other	14		<1		16

Sales/Revenue Statistics (a)


	2024		2023
MMBtu sales per retail customer	136		150
Revenue per retail customer	$	985	$	1,233
Residential revenue per MMBtu	8.92		9.18
C&I revenue per MMBtu	5.64		7.32
Transportation and other revenue per MMBtu	2.42		1.49

(a)See Note 6 to the consolidated financial statements for further information.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible.

Maximum daily output (firm and interruptible) and occurrence date:


2024		2023
MMBtu	Date	MMBtu	Date
841,164	Jan. 19	753,642	Feb. 3

Natural Gas Supply and Cost

NSP-Minnesota seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increases flexibility and decreases interruption, financial risks and customer rates. In addition, NSP-Minnesota conducts natural gas price hedging activities approved by its states’ commissions.

Average delivered cost per MMBtu of natural gas for regulated retail distribution:


2024		2023
$	3.97	$	5.31

Table of Contents

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.


General

General Economic Conditions

Economic conditions may have a material impact on NSP-Minnesota’s operating results. Management cannot predict the impact of fluctuating energy or commodity prices, pandemics, terrorist activity, war or the threat of war. We could experience a material impact to our results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in economic growth or a significant increase in interest rates or inflation.

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 warmer in the winter and cooler in the summer. Sales true-up and decoupling mechanisms mitigate the impacts of weather in certain jurisdictions.

Competition

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 solar generation and can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them in most jurisdictions.

Minnesota has incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to NSP-Minnesota’s electric service business with these incentives and federal tax subsidies.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. NSP-Minnesota’s wholesale customers can purchase energy from other generation resources and transmission services from other service providers to serve their native load.

FERC Order No. 1000 established competition for ownership of certain new electric transmission facilities under Federal regulations. Some states have state laws that allow the incumbent a Right of First Refusal to own these transmission facilities.

FERC Order 2222 requires that RTO and ISO markets allow participation of aggregations of distributed energy resources. This order is expected to incentivize distributed energy resource adoption; however implementation is expected to vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.

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. No municipalization activities are occurring presently.

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


Governmental Regulations

Public Utility Regulation

See Item 7 for discussion of public utility regulation.

Environmental Regulation

Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid and hazardous wastes or substances. Certain NSP-Minnesota activities require registrations, permits, licenses, inspections and approvals from these agencies.

NSP-Minnesota has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities strive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements.

However, it is not possible to determine what additional facilities or modifications to existing or planned facilities will be required as a result of changes to regulations, interpretations or enforcement policies or what effect future laws or regulations may have. We may be required to incur expenditures in the future for remediation of historic and current operating sites and other waste treatment, storage and disposal sites.

There are significant 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. Future environmental regulations may result in substantial costs. However, costs to comply with past environmental regulations have largely been recoverable through rates.

Emerging Environmental Regulation

Clean Air Act

Power Plant Greenhouse Gas Regulations — In April 2024, the EPA published final rules addressing control of CO2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO2 control requirements vary by subcategory. Based on current estimates and assumptions, NSP-Minnesota has determined that due to scheduled plant retirements, there is minimal financial or operational impact associated with these requirements and believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

Emerging Contaminants of Concern

PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS, but because PFAS are so ubiquitous in products and the environment, it may impact our operations.

In June 2024, the EPA finalized a rule that designated certain PFAS as hazardous substances under CERCLA. In July 2024, the EPA finalized another rule that set enforceable drinking water standards for certain PFAS.

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Potential costs for these rules and any additional proposed regulations related to PFAS are uncertain and will be determined on a site-specific basis where applicable. If costs are incurred, NSP - Minnesota believes the costs will be recoverable through rates based on prior state commission practices.

Effluent Limitation Guidelines

In April 2024, the EPA published final rules under the Clean Water Act, setting Effluent Limitations Guidelines and Standards for steam generating coal plants. This rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Based on current estimates and assumptions, NSP-Minnesota has determined that there is minimal financial or operational impact associated with these requirements and that any costs would be recoverable through rates based on prior state commission practices.

Other

Our operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all applicable laws, we do not believe the effects of compliance on our operations, financial condition or cash flows are material.


Employees

As of Dec. 31, 2024, NSP-Minnesota had 3,098 full-time employees and nine part-time employees, of which 2,103 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. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that NSP-Minnesota files with the SEC.

While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.

Oversight of Risk and Related Processes

NSP-Minnesota’s Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.

NSP-Minnesota maintains a robust compliance program and promotes a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our Code of Conduct and compliance policies, operation of formal risk management structures and overall business management. NSP-Minnesota further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls. Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.

Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental, safety and security risks.

The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of NSP-Minnesota. Processes are in place to confirm appropriate risk oversight, as well as identification and consideration of new risks.

Risks Associated with Our Business

Operational Risks

Our natural gas and electric generation/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 generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to customers, the public, employees or third-party contractors. We maintain insurance against most, 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 as well as potential reputational impact.

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Other uncertainties and risks inherent in operating and maintaining NSP-Minnesota's facilities include, but are not limited to:

•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.

•Failures in the availability, acquisition or transportation of fuel or other supplies.

•Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patterns.

•Performance below expected or contracted levels of output or efficiency.

•Availability of replacement or new equipment.

•Availability of adequate water resources and ability to satisfy water intake and discharge requirements.

•Inability to identify, manage properly or mitigate equipment defects.

•Use of new or unproven technology.

•Inability to use information effectively given the rapidly increasing volume of data.

•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.

•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.

•Increased costs due to aging infrastructure.

Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. 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. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time; however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.

Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.

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

Most 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 in-service dates and typically 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. Our long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where NSP-Minnesota operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.

In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.

The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.

We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

Our utility operations are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.

Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for NSP-Minnesota and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.

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 over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.

Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup 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.

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To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand.

Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy.

Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks.

Our utilities have physical and financial risks associated with wildfires.

In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and NSP-Minnesota's electric and natural gas infrastructure. Wildfires could jeopardize NSP-Minnesota’s electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories.

We have programs in place to mitigate the physical and financial risks associated with wildfires; however, NSP-Minnesota’s wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. Wildfires can occur even when NSP-Minnesota follows its procedures and implements its wildfire mitigation initiatives.

Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets.

While we carry liability insurance, given an extreme event, if NSP-Minnesota was found to be liable for wildfire damages, amounts could potentially exceed our coverage and negatively impact our results of operations, financial condition or cash flows.

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

A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost 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 and liquidity.

A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations.

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. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends.

Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations.

Due to the uncertainty involved in price movements and potential deviation from historical pricing, NSP-Minnesota is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, NSP-Minnesota cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, NSP-Minnesota’s results of operations, financial condition or cash flows could be materially impacted.

Failure to attract and retain a qualified workforce could have an adverse effect on operations.

The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate.

Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.

Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows.

National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.

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

We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines.

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Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.

We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. NSP-Minnesota does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us, we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.

We are subject to the risks of nuclear generation.

NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:

•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.

•Limitations on insurance available to cover losses that may 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.

•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.

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

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

We share in the electric production and transmission costs of the NSP-Wisconsin system, which is integrated with our system. Accordingly, our costs may be increased due to increased costs associated with NSP-Wisconsin’s system.

Our electric production and transmission system is managed on an integrated basis with the electric production and transmission system of NSP-Wisconsin. Pursuant to the Interchange Agreement between NSP-Wisconsin and us, we share, on a proportional basis, all costs related to the generation and transmission facilities of the entire integrated NSP System, including capital costs. Accordingly, if the costs to operate the NSP System increase, or revenue decreases, whether as a result of state or federally mandated improvements or otherwise, our costs could also increase and our revenues could decrease and we cannot guarantee a full recovery of such costs through our rates at the time the costs are incurred.

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 of Directors 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. 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, 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.

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 capital investment. Our rates are generally regulated and are 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.

There can also be no assurance that our regulatory commissions will judge all 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.

Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs required by commissions and result in less than full recovery.

Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.

Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that we will not be able to fully recover their costs from our customers.

Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could negatively impact our results of operations, financial condition or cash flows.

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

Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes 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 credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.

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 market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.

The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission our nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.

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 our cash flows and 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 unemployment rates.

Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may 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 we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance.

We may 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, (e.g., MISO), in which any credit losses are socialized to all market participants.

We have additional indirect credit exposure to financial institutions from 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.

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 either S&P or Moody’s Investor Services 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, 2024, Xcel Energy Inc. and its utility subsidiaries had approximately $27.3 billion of long-term debt and $1.8 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, 2024, Xcel Energy had the following guarantees outstanding:

•$951 million for performance and payment of Capital Services, LLC contracts for wind and solar generating equipment, with immaterial exposure.

•$29 million for performance on operating lease agreements, with $29 million of exposure.

•$93 million 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.

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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 of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future.

Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving NSP-Minnesota, would trigger settlement accounting and could require NSP-Minnesota to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.

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

Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.

Federal tax law may significantly impact our business.

NSP-Minnesota collects estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.

Additionally, NSP-Minnesota faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.

The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.

We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.

Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.

We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak.

Operations could be impacted by war, terrorism, or other 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 financial condition, results of operations 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 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, 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.

We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.

In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. NSP-Minnesota participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers.

A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.

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A cybersecurity 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 cybersecurity incidents, including those caused by human error.

The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations.

Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution 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 would likely receive state and federal regulatory scrutiny and 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 cybersecurity incident on 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.

Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.

Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant 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 cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.

While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.

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.

Public Policy Risks

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. FERC can impose penalties of up to $1.5 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. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.

In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.

The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.

In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.

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Environmental 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 may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.

In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions.

The steps NSP-Minnesota has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.

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

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.

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 facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. 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 sites where our past activities, or the activities of other parties, caused environmental contamination.

Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.

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 O&M costs incurred to comply with the requirements. Additionally, the impact of environmental laws and regulations may impact the economic health of consumers through higher prices of energy and purchased goods.

While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.

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.


ITEM 1B — UNRESOLVED STAFF COMMENTS

None.


ITEM 1C — CYBERSECURITY

NSP-Minnesota is a wholly owned subsidiary of Xcel Energy. As such, its cybersecurity processes are maintained by Xcel Energy management and governed by its Board of Directors.

As described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business.

The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.

Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed.

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Xcel Energy’s cybersecurity policies, standards, practices, annual cybersecurity training content and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.

Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.

Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown security threats.

The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.

The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at board meetings as well as at the ONES and Audit Committee meetings throughout the year.

While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the enterprise has the ability to notify and update the Board of Directors in the event of a possible crisis situation.

Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations. As of Feb. 27, 2025 there have been no material cybersecurity incidents to report.


ITEM 2 — PROPERTIES

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


Station, Location and Unit at Dec. 31, 2024	Fuel	Installed	MW (a)
Steam:
A.S. King-Bayport, MN, 1 Unit	Coal	1968	511
Sherco-Becker, MN
Unit 1	Coal	1976	680
Unit 3	Coal	1987	517	(b)
Monticello, MN, 1 Unit	Nuclear	1971	617
Prairie Island-Welch, MN
Unit 1	Nuclear	1973	521
Unit 2	Nuclear	1974	519
Various locations, 4 Units	Wood/RDF	Various	36	(c)
Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 Units	Natural Gas	1994 - 2005	343
Black Dog-Burnsville, MN, 3 Units	Natural Gas	1987 - 2018	491
Blue Lake-Shakopee, MN, 6 Units	Natural Gas/Oil	1974 - 2005	454
High Bridge-St. Paul, MN, 3 Units	Natural Gas	2008	530
Inver Hills-Inver Grove Heights, MN, 8 Units	Natural Gas/ Oil	1972 - 1996	276
Riverside-Minneapolis, MN, 3 Units	Natural Gas	2009	454
Hydro:
Hennepin Island-Minneapolis, MN 5 Units	Hydro	1954-1955	6
Wind:
Blazing Star 1-Lincoln County, MN, 100 Units	Wind	2020	200	(d)
Blazing Star 2-Lincoln County, MN, 100 Units	Wind	2021	200	(d)
Border-Rolette County, ND, 75 Units	Wind	2015	148	(d)
Community Wind North-Lincoln County, MN, 12 Units	Wind	2020	26	(d)
Courtenay Wind-Stutsman County, ND, 100 Units	Wind	2016	190	(d)
Crowned Ridge 2-Grant County, SD, 88 Units	Wind	2020	192	(d)
Dakota Range, SD, 72 Units	Wind	2022	298	(d)
Foxtail-Dickey County, ND, 75 Units	Wind	2019	150	(d)
Freeborn-Freeborn County, MN, 100 Units	Wind	2021	200	(d)
Grand Meadow-Mower County, MN, 67 Units	Wind	2008	100	(d)
Jeffers-Cottonwood County, MN, 20 Units	Wind	2020	43	(d)
Lake Benton-Pipestone County, MN, 44 Units	Wind	2019	99	(d)
Mower-Mower County, MN, 43 Units	Wind	2021	91	(d)
Nobles-Nobles County, MN, 133 Units	Wind	2010	200	(d)
Northern Wind-Murray County, MN, 37 Units	Wind	2023	92	(d)
Pleasant Valley-Mower County, MN, 100 Units	Wind	2015	196	(d)
Rock Aetna-Murray County, MN, 8 Units	Wind	2022	20	(d)
Solar:
Sherco Solar 1-Becker, MN, 63 units	Solar	2024	223
		Total	8,623

(a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity.

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

(c)RDF is made from municipal solid waste.

(d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota’s wind facilities had a weighted-average capacity factor of 46%.

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Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2024:


Conductor Miles
Transmission
500 KV			2,921
345 KV			13,182
230 KV			2,300
161 KV			640

115 KV			8,113
Less than 115 KV			6,627
Total Transmission			33,783

Distribution
Less than 115 KV			86,549

Total			120,332

NSP-Minnesota had 354 electric utility transmission and distribution substations at Dec. 31, 2024.

Natural gas utility mains at Dec. 31, 2024:


Miles
Transmission			78
Distribution			10,938


ITEM 3 — LEGAL PROCEEDINGS

NSP-Minnesota is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.

Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on NSP-Minnesota’s consolidated financial statements. Legal fees are generally expensed as incurred.

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 AND ISSUER 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.

The dividends declared during 2024 and 2023 were as follows:


(Millions of Dollars)	2024		2023
First quarter	$	101	$	132
Second quarter	103		112
Third quarter	99		181
Fourth quarter	150		221


ITEM 6 — [RESERVED]


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 of the results of operations set forth in General Instruction I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

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 ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that is 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 to the Board of Directors, 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.

Earnings Adjusted for Certain Items (Ongoing Earnings)

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

We use this non-GAAP financial measure to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

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The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:


(Millions of Dollars)	2024		2023
GAAP net income	$	793	$	707
Workforce reduction expenses	—		32
Sherco Unit 3 2011 outage refunds	47		—
Less: tax effect of adjustments	(13)		(9)
Ongoing earnings	$	827	$	730

Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In 2024, following contested case procedures, NSP-Minnesota recognized a customer refund of $47 million for replacement power incurred during the outage.

Workforce Reduction — In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs, and streamline the organization for long-term success. Xcel Energy initiated a voluntary retirement program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program.

Total Xcel Energy workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023, of which $32 million were attributable to NSP-Minnesota.


Results of Operations

2024 Comparison with 2023

NSP-Minnesota’s net income was approximately $793 million for 2024, compared with approximately $707 million for 2023. Ongoing net income was $827 million for 2024, compared to $730 million for 2023. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation and interest charges.

Electric Revenue

Electric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes.


(Millions of Dollars)	2024 vs. 2023
PTCs flowed back to customers (offset by lower ETR)	$	(277)
Recovery of lower electric fuel and purchased power expenses	(85)
2011 Sherco 3 outage refunds (a)	(47)
Sales and demand (b)	(17)
Estimated impact of weather (net of sales true-up)	(7)
Regulatory rate outcomes	197
Non-fuel riders	86
Conservation and DSM (offset in expense)	62
Wholesale generation revenues	12
Other, net	(66)
Total decrease	$	(142)

(a)See “Non-GAAP Financial Measures” section for additional information.

(b)Sales excludes weather impact, net of sales true-up mechanism in Minnesota.

Natural Gas Revenues

Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.


(Millions of Dollars)	2024 vs. 2023
Recovery of lower natural gas costs	$	(173)
Regulatory rate outcomes	55
Infrastructure and integrity riders	8
Other, net	9


Total decrease	$	(101)

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.

Electric fuel and purchased power expenses decreased $81 million in 2024. The decrease is primarily due to decreased volumes and timing of fuel recovery mechanisms, partially offset by increased wholesale activity.

Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.

Natural gas sold and transported decreased $171 million in 2024. The decrease is primarily due lower commodity prices, timing of fuel recovery and decreased volume.

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $27 million in 2024. The increase is primarily due to operational activities, including generation maintenance and storm response, partially offset by lower labor and benefit costs and lower bad debt expenses.

Depreciation and Amortization — Depreciation and amortization expense increased $125 million in 2024.This is a result of system expansion partially offset by wind and nuclear life extensions implemented in 2023 in the Minnesota Electric Rate Case.

Interest Charges — Interest charges increased $38 million in 2024, largely due to higher long-term debt levels and higher interest rates.

Income Taxes — Income tax benefit increased $247 million in 2024, largely due to the addition of nuclear PTCs, newly available in 2024. PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income.


Public Utility Regulation

The FERC and various state and local regulatory commissions regulate NSP-Minnesota. NSP-Minnesota is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota and South Dakota.

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Rates are designed to recover plant investment, operating costs and an allowed return on investment. NSP-Minnesota requests changes in utility rates through commission filings. Changes in operating costs can affect NSP-Minnesota’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.

In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact NSP-Minnesota’s results of operations and credit quality.

See Rate Matters and Other within Note 12 to the consolidated financial statements for further information.

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction


Regulatory Body / RTO						Additional Information
MPUC						Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans.
NDPSC						Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance.
SDPUC						Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance.
FERC						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.
MISO						NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. 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.
DOT						Pipeline safety compliance.
Minnesota Office of Pipeline Safety						Pipeline safety compliance.

Recovery Mechanisms


Mechanism						Additional Information
CIP Rider						Recovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.

Customer Protection Mechanisms						MISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers.
Decoupling						Measures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.
FCA						Recovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).
Gas Utility Infrastructure Cost Rider						Recovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.
Infrastructure Rider						Recovers costs for investments in generation in South Dakota.
Purchased Gas Adjustment						Provides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.
Renewable Development Fund Rider						Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.
Renewable Energy Rider						Recovers cost of renewable generation in North Dakota.
RES Rider						Recovers cost of renewable generation in Minnesota.
Sales True-up						Mitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers.
State Energy Policy Electric Rider						Recovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.
Transmission Cost Recovery Rider						Recovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization.

Pending and Recently Concluded Regulatory Proceedings

2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%.

In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms:

•Natural gas rate increase of $46 million, or 7.5%.

•ROE of 9.6%.

•Equity ratio of 52.5%.

•Rate base of $1.25 billion.

•No change to Commission approved decoupling.

In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.

2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million.

In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025.

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2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC.

In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.

In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.

In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.

2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.

2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).

Nuclear Power Operations

Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.

NRC Regulation — The NRC regulates nuclear operations. 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 and expects to recover future compliance costs.

Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.

High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of 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. Currently, there are no definitive plans for a permanent federal storage facility site.

Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.

In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.

In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.

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.

NSP System

Pending and Recently Concluded Regulatory Proceedings

Resource Acquisition — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC. In October 2024, NSP-Minnesota filed a settlement with several parties reaching agreement on the resource plan, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition.

In February 2025, the MPUC verbally approved the terms of the settlement agreement, including:

•The selection of the company owned 420 MW Lyon County combustion turbine.

•The selection of the company owned 300 MW 4-hour Sherco battery energy storage system.

•Multiple PPAs to proceed to the negotiation stage.

•The addition of 3,200 MW of wind, 400 MW of solar and 600 MW of stand-alone storage to be added through 2030 based on an RFP process (a portion of which is expected to be fulfilled with the resources acquired as part of the 2024 RFPs). Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line.

•Planned life extensions of the Prairie Island and Monticello nuclear plants through the early 2050s.

Additionally, the MPUC approved life extensions of the Red Wing and Mankato RDF plants to 2037 and ordered NSP-Minnesota to file a proposed tariff for customers with super-large load, largely data centers, by July 15, 2025.

NSP-Minnesota will file additional RFPs for approved resource needs beginning in late 2025 or early 2026.

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NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.

•In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023. NSP-Minnesota expects to file for approval of recommended projects in summer 2025.

•In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit. Bids are currently under evaluation; NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025 and plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second half of 2025.

Purchased Power and Transmission Services

The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.

Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. 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.

Wholesale and Commodity Marketing Operations

NSP-Minnesota conducts 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 risk and to hedge sales and purchases.

NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates.


Other

Supply Chain

NSP-Minnesota’s ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain.

Large global demand for energy-related infrastructure has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction

resources to build renewables and gas generation has also been strained, impacting cost and availability.

In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. NSP-Minnesota continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work.

Tariffs and Trade Complaints

In May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells from Cambodia, Malaysia, Thailand and Vietnam, whether or not assembled into modules.

In October 2024, the U.S. Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact NSP-Minnesota projects. In November 2024, the U.S. Department of Commerce concluded that dumping had occurred and the impact to NSP-Minnesota is still being evaluated.

In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures. The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications.

In January of 2025, the U.S. International Trade Commission made an affirmative determination in the preliminary phase of the anti-dumping and countervailing duty investigations concerning Active Anode Material, a component of lithium-ion batteries, from China. This case will be reviewed by the U.S. Department of Commerce and the International Trade Commission over the course of 2025.

In early 2025, several executive orders were issued, some of which impose new tariffs on certain imports, which may impact our procurement activities.

NSP-Minnesota continues to assess the impacts of these tariffs, trade complaints and federal policies on its business, including company owned projects and PPAs. NSP-Minnesota may seek regulatory relief for tariffs, if required, in its jurisdictions.

Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs.


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 for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

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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 on the contracts underlying its derivatives, the contracts expose NSP-Minnesota to credit and non-performance risk.

Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.

Commodity Price Risk — We are exposed to commodity price risk in our 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. Our risk management policy allows us 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.

Fair value of net commodity trading contracts as of Dec. 31, 2024:


	Futures/ Forwards Maturity
(Millions of Dollars)		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)		$	(16)	$	(19)	$	(4)	$	—	$	(39)
NSP-Minnesota (b)		3		10		(4)		2		11
		$	(13)	$	(9)	$	(8)	$	2	$	(28)


	Options Maturity
(Millions of Dollars)		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)		$	—	$	—	$	20	$	—	$	20

(a)Prices actively quoted or based on actively quoted prices.

(b)Prices based on models and other valuation methods.

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


(Millions of Dollars)	2024		2023
Fair value of commodity trading net contracts outstanding at Jan. 1	$	(4)	$	(10)
Contracts realized or settled during the period	8		10
Commodity trading contract additions and changes during the period	(12)		(4)
Fair value of commodity trading net contracts outstanding at Dec. 31	$	(8)	$	(4)

A 10% increase and 10% decrease in forward market prices for NSP-Minnesota’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $1 million at both Dec. 31, 2024 and Dec. 31, 2023. Market price movements can exceed 10% under abnormal circumstances.

Xcel Energy’s commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:


(Millions of Dollars)	Year Ended Dec. 31		Average		High		Low
2024	$	—	$	—	$	1	$	—
2023	—		—		1		—

Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received.

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.

A 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense annually by approximately $2 million each in 2024 and 2023.

NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate 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.

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. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.

The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. NSP-Minnesota’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.

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 monitors these policies to reflect changes and scope of operations.

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At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $20 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $20 million. At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $22 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $22 million.

NSP-Minnesota conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs 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

Derivative contracts, with the exception of those designated as normal purchases and normal sales, 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.


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.

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Management Report on Internal Control 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, 2024. 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, 2024, NSP-Minnesota’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.


/s/ ROBERT C. FRENZEL						/s/ BRIAN J. VAN ABEL
Robert C. Frenzel						Brian J. Van Abel
Chairman, Chief Executive Officer and Director						Executive Vice President, Chief Financial Officer and Director
Feb. 27, 2025						Feb. 27, 2025

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors 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, 2024 and 2023, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, 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.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 10 to the consolidated financial statements.

Critical Audit Matter Description

The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric distribution companies in Minnesota, North Dakota and South Dakota, and natural gas distribution companies in Minnesota and North Dakota. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.

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The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and requirements to refund amounts to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the Commissions for the Company, other regulatory filings, legal decisions and recommendations being evaluated by the Commissions, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates. We evaluated historic orders for precedents of the Commissions’ treatment of similar costs under similar circumstances. We compared the regulatory orders, filings and other publicly available information to the Company’s recorded regulatory assets and liabilities for completeness.

•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.


/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 27, 2025

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

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in millions)


	Year Ended Dec. 31
	2024		2023		2022
Operating revenues
Electric, non-affiliates	$	4,639	$	4,748	$	5,103
Electric, affiliates	460		493		514
Natural gas	653		754		1,022
Other	15		48		45
Total operating revenues	5,767		6,043		6,684

Operating expenses
Electric fuel and purchased power	1,988		2,069		2,416
Cost of natural gas sold and transported	295		466		741
Cost of sales — other	4		30		26
Operating and maintenance expenses	1,271		1,244		1,228
Conservation and demand side management expenses	181		118		163
Depreciation and amortization	1,106		981		1,014
Taxes (other than income taxes)	212		237		276
Workforce reduction expenses	—		32		—
Total operating expenses	5,057		5,177		5,864

Operating income	710		866		820

Other income (expense), net	11		—		(7)
Allowance for funds used during construction — equity	53		36		29

Interest charges and financing costs
Interest charges and other financing costs	363		325		291
Allowance for funds used during construction — debt	(26)		(21)		(12)
Total interest charges and financing costs	337		304		279

Income before income taxes	437		598		563
Income tax benefit	(356)		(109)		(112)
Net income	$	793	$	707	$	675

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in millions)


	Year Ended Dec. 31
	2024		2023		2022
Net income	$	793	$	707	$	675

Other comprehensive income (loss)

Pension and retiree medical benefits:
Net pension and retiree medical gain arising during the period, net of tax	—		—		1

Derivative instruments:
Net fair value increase (decrease), net of tax	12		(3)		—
Reclassification of losses to net income, net of tax	—		1		1



Total other comprehensive income (loss)	12		(2)		2
Total comprehensive income	$	805	$	705	$	677

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in millions)


	Year Ended Dec. 31
	2024		2023		2022
Operating activities
Net income	$	793	$	707	$	675
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,112		988		1,021
Nuclear fuel amortization	106		96		118
Deferred income taxes	141		214		(214)
Allowance for equity funds used during construction	(53)		(36)		(29)
Provision for bad debts	15		30		21
Changes in operating assets and liabilities:
Accounts receivable	(42)		1		(102)
Accrued unbilled revenues	18		82		(53)
Inventories	(24)		(27)		(85)
Other current assets	(48)		(19)		(4)
Accounts payable	59		(64)		46
Net regulatory assets and liabilities	108		287		443
Other current liabilities	(214)		56		39
Pension and other employee benefit obligations	(42)		(15)		(11)
Other, net	(11)		1		6
Net cash provided by operating activities	1,918		2,301		1,871

Investing activities
Capital/construction expenditures	(2,803)		(2,282)		(1,901)
Purchase of investment securities	(998)		(994)		(1,332)
Proceeds from the sale of investment securities	961		959		1,297
Investments in utility money pool arrangement	(390)		(300)		(1,522)
Repayments from utility money pool arrangement	414		243		1,613
Other, net	(3)		(3)		6
Net cash used in investing activities	(2,819)		(2,377)		(1,839)

Financing activities
Proceeds from (repayments of) short-term borrowings, net	30		(42)		207
Borrowings under utility money pool arrangement	271		302		6
Repayments under utility money pool arrangement	(271)		(302)		(6)
Proceeds from issuance of long-term debt	687		783		489
Repayment of long-term debt	—		(400)		(300)
Capital contributions from parent	715		351		124
Dividends paid to parent	(494)		(647)		(560)

Net cash provided by (used in) financing activities	938		45		(40)

Net change in cash, cash equivalents and restricted cash	37		(31)		(8)
Cash, cash equivalents and restricted cash at beginning of period	34		65		73
Cash, cash equivalents and restricted cash at end of period	$	71	$	34	$	65

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(313)	$	(294)	$	(268)
Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers	446		256		(100)

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	500	$	218	$	208
Inventory transfers to property, plant and equipment	41		55		10
Operating lease right-of-use assets	39		216		1
Allowance for equity funds used during construction	53		36		29

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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


	Dec. 31
	2024		2023
Assets
Current assets
Cash and cash equivalents	$	71	$	34
Accounts receivable, net	530		490
Accounts receivable from affiliates	1		15
Investments in money pool arrangements	33		57
Accrued unbilled revenues	272		290
Inventories	339		356
Regulatory assets	364		250
Derivative instruments	36		50
Prepayments and other	139		87
Total current assets	1,785		1,629

Property, plant and equipment, net	20,860		18,757

Other assets
Nuclear decommissioning fund and other investments	3,548		3,262
Regulatory assets	813		837
Derivative instruments	67		61
Operating lease right-of-use assets	393		439
Other	19		16
Total other assets	4,840		4,615
Total assets	$	27,485	$	25,001

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	250	$	—
Short-term debt	195		165
Accounts payable	631		579
Accounts payable to affiliates	100		89
Regulatory liabilities	543		300
Taxes accrued	221		223
Accrued interest	90		79
Dividends payable to parent	80		121
Derivative instruments	31		44
Operating lease liabilities	97		91
Other	150		351
Total current liabilities	2,388		2,042

Deferred credits and other liabilities
Deferred income taxes	2,238		1,992
Deferred investment tax credits	13		14
Regulatory liabilities	2,155		2,097
Asset retirement obligations	3,073		2,658
Derivative instruments	77		86
Pension and employee benefit obligations	151		168
Operating lease liabilities	317		372
Other	28		35
Total deferred credits and other liabilities	8,052		7,422

Commitments and contingencies
Capitalization
Long-term debt	7,607		7,330
Long-term debt — related parties	166		—
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2024 and Dec. 31, 2023, respectively	—		—
Additional paid in capital	6,399		5,686
Retained earnings	2,881		2,541
Accumulated other comprehensive loss	(8)		(20)
Total common stockholder's equity	9,272		8,207
Total liabilities and equity	$	27,485	$	25,001

See Notes to Consolidated Financial Statements

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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, 2021	1,000,000	$	—	$	5,202	$	2,391	$	(20)	$	7,573

Net income						675				675
Other comprehensive income								2		2
Dividends declared to parent						(586)				(586)
Contribution of capital by parent				172						172

Balance at Dec. 31, 2022	1,000,000	$	—	$	5,374	$	2,480	$	(18)	$	7,836

Net income						707				707
Other comprehensive loss								(2)		(2)
Dividends declared to parent						(646)				(646)
Contribution of capital by parent				312						312

Balance at Dec. 31, 2023	1,000,000	$	—	$	5,686	$	2,541	$	(20)	$	8,207

Net income						793				793
Other comprehensive income								12		12
Dividends declared to parent						(453)				(453)
Contribution of capital by parent				713						713

Balance at Dec. 31, 2024	1,000,000	$	—	$	6,399	$	2,881	$	(8)	$	9,272

See Notes to Consolidated Financial Statements

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NORTHERN STATES POWER COMPANY - MINNESOTA

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 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.

Investments in certain plants and transmission facilities are 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 operating costs associated with these facilities is included in its consolidated statements of income.

NSP-Minnesota’s consolidated financial statements are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

NSP-Minnesota has evaluated events occurring after Dec. 31, 2024 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 to record transactions and balances resulting from business operations.

Estimates are used for 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 actual amounts can be determined. 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.

•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 and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. 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. 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 recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing 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.

Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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, refundable to utility customers over the remaining life of the related assets. NSP-Minnesota anticipates that a tax rate increase would predominantly result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected.

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 over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and NSP-Minnesota tax elections. For tax credits otherwise eligible to be recognized when earned, NSP-Minnesota considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities.

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. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740, Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in regulatory mechanisms.

NSP-Minnesota measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the 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 expense.

Interest and penalties related to income taxes are reported within Other income (expense), net or interest charges in the consolidated statements of income.

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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 in Regulated Operations — 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 and replacement of items determined to be less than a unit of property are charged to expense as incurred.

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.

Depreciation expense is recorded using the straight-line method over the plant’s commission approved 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. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.9% for 2024, 3.7% for 2023 and 4.0% for 2022.

See Note 3 for further information.

AROs — NSP-Minnesota records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated 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 typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.

See Note 10 for further information.

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every three years and submitted to the state commissions for approval. The latest decommissioning study was deferred one year and completed in 2024.

NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. 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 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 amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for 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 is performed. 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.

Estimated future expenditures to restore sites are generally 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. When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied.

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 systematically 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.

A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are net of any excise or sales taxes or fees.

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NSP-Minnesota recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO 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 three 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, 2024 and 2023, the allowance for bad debts was $42 million and $48 million, respectively.

Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following:


(Millions of Dollars)	Dec. 31, 2024		Dec. 31, 2023
Inventories
Materials and supplies	$	234	$	219
Fuel	81		105
Natural gas	24		32
Total inventories	$	339	$	356

Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, rabbi trust assets, commodity derivatives, pension and postretirement plan assets and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate 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, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.

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

See Notes 8 and 9 for further information.

Derivative Instruments — NSP-Minnesota uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives 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.

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

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 and 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.

Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items.

Billing amounts are revised periodically for differences between 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.

See Note 6 for further information.

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Conservation Programs — Costs incurred for DSM and 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 the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any 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 costs over the period between refueling outages consistent with rate recovery.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. An inventory accounting model is used to account for RECs.

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.

Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.


2. Accounting Pronouncements

Recently Adopted

Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. NSP-Minnesota implemented this guidance on a retrospective basis in the year ended Dec. 31, 2024. The adoption impacts were not material.

See Note 12 for further information.

Recently Issued

Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and NSP-Minnesota does not expect implementation of the new disclosure guidance to have a material impact on its consolidated financial statements.

Climate-Related Disclosures — In March 2024, the SEC issued Final Rule 33-11275 – The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 GHG emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions. The rule requires implementation in phases between 2025 and 2033. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. NSP-Minnesota does not expect the potential implementation of the new guidance to have a material impact on the consolidated financial statements.

Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses, which requires disaggregated disclosure of income statement expenses for public business entities. The ASU is effective for annual periods beginning after Dec. 15, 2026. NSP-Minnesota is currently evaluating the impact of implementing the new disclosure guidance.


3. Property, Plant and Equipment

Major classes of property, plant and equipment


(Millions of Dollars)	Dec. 31, 2024		Dec. 31, 2023
Property, plant and equipment, net
Electric plant	$	23,218	$	21,206
Natural gas plant	2,472		2,256
Common and other property	1,450		1,301
Plant to be retired (a)	554		604
CWIP	1,522		1,085
Total property, plant and equipment	29,216		26,452
Less accumulated depreciation	(8,753)		(8,044)
Nuclear fuel	3,491		3,337
Less accumulated amortization	(3,094)		(2,988)
Property, plant and equipment, net	$	20,860	$	18,757

(a)Amounts include Sherco 1 and 3 and A.S. King. Balance is presented net of accumulated depreciation.

Joint Ownership of Generation and Transmission Facilities

Jointly owned assets as of Dec. 31, 2024:


(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		Percent Owned
Electric generation:
Sherco Unit 3	$	636	$	499	59	%
Sherco common facilities	189		128		80
Sherco substation	5		4		59
Electric transmission:
Grand Meadow	11		4		50
Huntley Wilmarth	49		3		50
CapX2020	855		160		51
Total (a)	$	1,745	$	798

(a)Projects additionally include $10 million in CWIP.

NSPM separately records its share of operating expenses and construction expenditures. 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, 2024				Dec. 31, 2023
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	21	$	339	$	18	$	340
Recoverable deferred taxes on AFUDC		Plant lives	—		137		—		127
Excess deferred taxes — TCJA	7	Various	8		87		8		96
MISO capacity revenue tracker		One to two years	63		45		36		26
Prairie Island extended power uprate		10 years	4		34		4		38
Benson biomass PPA termination and asset purchase		Four years	10		26		10		36
Deferred purchased natural gas		One to two years	51		25		16		58
Sales true-up and revenue decoupling		One to two years	60		23		7		2
Nuclear refueling outage costs	1	One to two years	51		20		43		19
Contract valuation adjustments (a)	1, 8	Term of related contract	7		16		9		22
Purchased power contracts costs		Term of related contract	1		16		1		20
Conservation programs (b)	1	One to two years	8		15		6		19

Renewable resources and environmental initiatives		Less than one year	34		—		38		—

Gas pipeline inspection and remediation costs		Less than one year	30		—		37		—

Other		Various	16		30		17		34
Total regulatory assets			$	364	$	813	$	250	$	837

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

(b)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, 2024				Dec. 31, 2023
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	5	$	1,105	$	5	$	1,157
Plant removal costs	1, 10	Various	—		815		—		741
Net AROs (b)		Various	—		161		—		90
Renewable resources and environmental initiatives		Various	16		38		9		27

Deferred natural gas and electric energy/fuel costs (c)		One to two years	348		12		143		—


Conservation programs		Less than one year	41		—		27		—
Contract valuation adjustments (d)	1, 8	Less than one year	21		—		16		—

Other		Various	112		24		100		82
Total regulatory liabilities (e)			$	543	$	2,155	$	300	$	2,097

(a)Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.

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

(c)Includes Nuclear PTCs.

(d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.

(e)Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities.

NSP-Minnesota’s regulatory assets not earning a return include past expenditures of $562 million and $479 million at Dec. 31, 2024 and 2023, respectively, which predominately relate to purchased natural gas (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return.

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5. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

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

Money pool borrowings:


(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2024			Year Ended Dec. 31
				2024			2023			2022
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	—			—			—			—
Average amount outstanding	31			10			17			—
Maximum amount outstanding	139			139			135			4
Weighted average interest rate, computed on a daily basis	4.62		%	4.82		%	4.97		%	3.87		%
Weighted average interest rate at period end	N/A			N/A			N/A			N/A

Commercial Paper — Commercial paper outstanding:


(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2024			Year Ended Dec. 31
				2024			2023			2022
Borrowing limit	$	700		$	700		$	700		$	700
Amount outstanding at period end	195			195			165			207
Average amount outstanding	24			54			92			21
Maximum amount outstanding	215			400			441			290
Weighted average interest rate, computed on a daily basis	4.62		%	5.39		%	4.99		%	4.14		%
Weighted average interest rate at end of period	4.63			4.63			5.47			4.64

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, 2024 and 2023, there were $12 million and $15 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use commercial paper programs to fulfill short-term funding needs, NSP-Minnesota must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities.

The lines of credit provide 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 of dollars)		Additional Periods for Which a One-Year Extension May Be Requested (b)
2024		2023
47.0	%	47.7	%	$	150	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 would 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, 2024, NSP-Minnesota was in compliance with the financial covenant on its debt agreements.

NSP-Minnesota had the following committed credit facility available as of Dec. 31, 2024 (in millions of dollars):


Credit Facility (a)		Drawn (b)		Available
$	700	$	207	$	493

(a)This credit facility matures in September 2027.

(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, 2024 and 2023.

Bilateral Credit Agreement — In April 2024, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of Dec. 31, 2024, and 2023 NSP-Minnesota had $74 million and $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement, respectively.

Long-Term Borrowings and Other Financing Instruments

Generally, the property of NSP-Minnesota is subject to the lien of its first mortgage indenture for the benefit of bondholders. 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.

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Long term debt obligations for NSP-Minnesota as of Dec. 31 (in millions of dollars):


Financing Instrument	Interest Rate	Maturity Date	2024		2023

First mortgage bonds	7.125	July 1, 2025	250		250
First mortgage bonds	6.50	March 1, 2028	150		150
First mortgage bonds	2.25	April 1, 2031	425		425
First mortgage bonds	5.25	July 15, 2035	250		250
First mortgage bonds	6.25	June 1, 2036	400		400
First mortgage bonds	6.20	July 1, 2037	350		350
First mortgage bonds	5.35	Nov. 1, 2039	300		300
First mortgage bonds	4.85	Aug. 15, 2040	250		250
First mortgage bonds	3.40	Aug. 15, 2042	500		500
First mortgage bonds	4.125	May 15, 2044	300		300
First mortgage bonds	4.00	Aug. 15, 2045	300		300
First mortgage bonds	3.60	May 15, 2046	350		350
First mortgage bonds	3.60	Sept. 15, 2047	600		600
First mortgage bonds	2.90	March 1, 2050	600		600
First mortgage bonds (a)	2.60	June 1, 2051	700		700
First mortgage bonds	3.20	April 1, 2052	425		425
First mortgage bonds	4.50	June 1, 2052	500		500
First mortgage bonds (b)	5.10	May 15, 2053	800		800
First mortgage bonds (c)	5.40	March 15, 2054	700		—
Other long-term debt			2		2
Long-term debt — related parties principal amount outstanding (a)	2.60	Jun 1, 2051	(166)		—
Unamortized discount			(49)		(49)
Unamortized debt issuance cost			(80)		(73)
Current maturities			(250)		—
Total long-term debt			$	7,607	$	7,330

(a)During 2024, Xcel Energy Inc. purchased a portion of these NSP-Minnesota first mortgage bonds for $105 million. Interest expense related to these repurchased bonds was immaterial for the year ended Dec. 31, 2024.

(b)2023 financing.

Maturities of long-term debt are as follows:


(Millions of Dollars)
2025	$	250
2026	—
2027	—
2028	150
2029	—

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 commissions additionally impose dividend limitations, which are more restrictive than those imposed by the FERC.

Requirements and actuals as of Dec. 31, 2024:


Equity to Total Capitalization Ratio Required Range				Equity to Total Capitalization Ratio Actual
Low		High		2024
47.6	%	58.2	%	53.0	%


Unrestricted Retained Earnings			Total Capitalization			Limit on Total Capitalization
$	1,809	million	$	17,490	million	$	17,800	million


6. Revenues

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


	Year Ended Dec. 31, 2024
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,496	$	328	$	7	$	1,831
C&I	2,191		221		—		2,412
Other	36		—		8		44
Total retail	3,723		549		15		4,287
Wholesale	319		—		—		319
Transmission	262		—		—		262
Interchange and other	446		31		—		477

Total revenue from contracts with customers	4,750		580		15		5,345
Alternative revenue and other	349		73		—		422
Total revenues	$	5,099	$	653	$	15	$	5,767


	Year Ended Dec. 31, 2023
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,524	$	368	$	41	$	1,933
C&I	2,298		309		—		2,607
Other	34		—		7		41
Total retail	3,856		677		48		4,581
Wholesale	354		—		—		354
Transmission	263		—		—		263
Interchange and other	493		18		—		511

Total revenue from contracts with customers	4,966		695		48		5,709
Alternative revenue and other	275		59		—		334
Total revenues	$	5,241	$	754	$	48	$	6,043

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	Year Ended Dec. 31, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,463	$	510	$	38	$	2,011
C&I	2,376		433		—		2,809
Other	38		—		7		45
Total retail	3,877		943		45		4,865
Wholesale	668		—		—		668
Transmission	287		—		—		287
Interchange and other	529		19		—		548

Total revenue from contracts with customers	5,361		962		45		6,368
Alternative revenue and other	256		60		—		316
Total revenues	$	5,617	$	1,022	$	45	$	6,684


7. Income Taxes

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:


	2024		2023		2022
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	7.1		7.0		7.0
Increases (decreases) in tax from:
PTCs (a)	(99.4)		(39.5)		(39.6)
Plant regulatory differences (b)	(9.2)		(5.7)		(6.7)
Other tax credits, net NOL & tax credit allowances	(1.9)		(1.3)		(1.3)
Other, net	0.9		0.3		(0.3)
Effective income tax rate	(81.5)	%	(18.2)	%	(19.9)	%

(a)Wind, Solar, and Nuclear PTCs (net of estimated transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings. Nuclear PTCs, newly available in 2024, resulted in benefits of 39.5% to the ETR for the year ended Dec. 31, 2024.

(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

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


(Millions of Dollars)	2024		2023		2022
Current federal tax (benefit) expense	$	(149)	$	(154)	$	70
Current state tax (benefit) expense	(25)		3		26
Current change in unrecognized tax expense (benefit)	3		(21)		8
Deferred federal tax (benefit) expense	(244)		5		(237)
Deferred state tax expense	61		51		23
Deferred change in unrecognized tax (benefit) expense	(1)		8		—
Deferred ITCs	(1)		(1)		(2)
Total income tax benefit	$	(356)	$	(109)	$	(112)

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


(Millions of Dollars)	2024		2023		2022
Deferred tax expense (benefit) excluding items below	$	246	$	326	(283)
Adjustments to deferred income taxes for tax credit cash transfers (a)	(325)		(150)		—
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(99)		(114)		70
Tax (expense) benefit allocated to other comprehensive income and other	(6)		2		(1)
Deferred tax (benefit) expense	$	(184)	$	64	$	(214)

(a)Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.

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


(Millions of Dollars)	2024		2023 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	3,150	$	2,938
Regulatory assets	234		173
Operating lease assets	115		129
Pension expense	67		64
Deferred fuel costs	21		20
Other	21		9
Total deferred tax liabilities	$	3,608	$	3,333

Deferred tax assets:
Tax credit carryforward	$	875	$	832
Regulatory liabilities	358		306
Operating lease liabilities	115		129
Rate refund	10		59
NOL and tax credit valuation allowances	(68)		(57)
Other employee benefits	28		31
Deferred ITCs	4		4
Other	48		37
Total deferred tax assets	$	1,370	$	1,341
Net deferred tax liability	$	2,238	$	1,992

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

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)	2024		2023
Federal tax credit carryforwards	$	815	$	777
Valuation allowances for federal credit carryforwards	(11)		(5)
State NOL carryforwards	—		1
State tax credit carryforwards, net of federal detriment (a)	60		55
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(57)		(52)

(a)State tax credit carryforwards are net of federal detriment of $16 million and $15 million as of Dec. 31, 2024 and 2023, respectively.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $15 million and $14 million as of Dec. 31, 2024 and 2023, respectively.

Federal carryforward periods expire between 2038 and 2044. State carryforward periods, not including those with indefinite carryforward periods, expire between 2025 and 2036.

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Unrecognized Tax Benefits

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
2014 - 2016						March 2025
2021						October 2025

Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim filed in 2020 has been extended. In 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agreed with the report and re-recognized the related benefit in 2023.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns. As of Dec. 31, 2024, NSP-Minnesota’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:

State

Tax Year(s)

Expiration

Minnesota

2014-2016

September 2025

Minnesota

2020

June 2025

There are currently no state income tax audits in progress.

Unrecognized tax benefit balance may include permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance may include temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.

Unrecognized tax benefits - permanent vs temporary:


(Millions of Dollars)	Dec. 31, 2024		Dec. 31, 2023
Unrecognized tax benefit — Permanent tax positions	$	20	$	18
Unrecognized tax benefit — Temporary tax positions	—		—
Total unrecognized tax benefit	$	20	$	18

Changes in unrecognized tax benefits:


(Millions of Dollars)	2024		2023		2022
Balance at Jan. 1	$	18	$	34	$	26
Additions based on tax positions related to the current year	3		2		2
Additions for tax positions of prior years	—		1		6
Reductions for tax positions of prior years	(1)		(18)		—
Reductions for tax positions related to settlements with taxing authorities	—		(1)		—
Balance at Dec. 31	$	20	$	18	$	34

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


(Millions of Dollars)	Dec. 31, 2024		Dec. 31, 2023
NOL and tax credit carryforwards	$	(17)	$	(18)

There exists approximately $20 million of noncurrent liabilities related to unrecognized tax benefits for which there is uncertainty about if or when these liabilities will significantly increase or decrease.

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)	2024		2023		2022
Receivable (payable) for interest related to unrecognized tax benefits at Jan. 1	$	1	$	(3)	$	(2)
Interest (expense) benefit related to unrecognized tax benefits	(1)		4		(1)
Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31	$	—	$	1	$	(3)

No penalties were accrued related to unrecognized tax benefits as of Dec. 31, 2024, 2023 or 2022.


8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.

•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 actively traded instruments with observable actual trading prices.

•Level 2 — Pricing inputs are other than actual trading 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 include those valued with models requiring significant judgment or estimation.

Specific valuation methods include:

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 funds 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 may be redeemed with proper notice, however, withdrawals 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 — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — 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 contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.

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Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.

The values of these instruments are derived from, and designed to offset, the costs 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 these instruments. FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.

Net congestion costs, including the impact of FTR settlements are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund

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 investment targets by asset class for the 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 $1.4 billion and $1.2 billion as of Dec. 31, 2024 and 2023, respectively, and unrealized losses were $49 million and $29 million as of Dec. 31, 2024 and 2023, respectively.

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


	Dec. 31, 2024
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	39	$	39	$	—	$	—	$	—	$	39
Commingled funds	703		—		—		—		1,025		1,025
Debt securities	866		—		832		14		—		846
Equity securities	522		1,583		1		—		—		1,584
Total	$	2,130	$	1,622	$	833	$	14	$	1,025	$	3,494

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $54 million of other miscellaneous investments.


	Dec. 31, 2023
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	41	$	41	$	—	$	—	$	—	$	41
Commingled funds	721		—		—		—		1,049		1,049
Debt securities	784		—		771		9		—		780
Equity securities	508		1,339		2		—		—		1,341
Total	$	2,054	$	1,380	$	773	$	9	$	1,049	$	3,211

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments.

For the years ended Dec. 31, 2024 and 2023, there were immaterial 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, 2024:


	Final Contractual Maturity
(Millions of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	7	$	308	$	269	$	262	$	846

Derivative Activities and 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 and utility commodity prices.

Interest Rate Derivatives — NSP-Minnesota enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.

As of Dec. 31, 2024, accumulated other comprehensive loss related to interest rate derivatives included immaterial of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2024, NSP-Minnesota had no unsettled interest rate swaps outstanding.

See Note 11 for the financial impact of qualifying interest rate 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.

Wholesale and Commodity Trading — 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 the activities governed by this policy.

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Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.

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. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.

The most significant derivative positions outstanding at Dec. 31, 2024 and 2023 for this purpose relate to FTR instruments administered by MISO. These instruments are intended to offset the impacts of transmission system congestion.

When NSP-Minnesota enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms. As of Dec. 31, 2024, NSP-Minnesota had no commodity contracts designated as cash flow hedges.

Gross notional amounts of commodity forwards, options and FTRs:


(Amounts in Millions) (a)(b)	Dec. 31, 2024	Dec. 31, 2023
MWh of electricity	31	38
MMBtu of natural gas	57	64

(a)Not reflective of net positions in the underlying commodities.

(b)Notional amounts for options 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 on the consolidated balance sheets. NSP-Minnesota often has significant concentrations of credit risk with particular entities or industries in its wholesale, trading and non-trading commodity activities.

As of Dec. 31, 2024, six of NSP-Minnesota’s ten most significant counterparties for these activities, comprising $20 million or 22% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.

One of the ten most significant counterparties, comprising $27 million or 29% of this credit exposure, were not rated by these external ratings agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade.

Three of these significant counterparties, comprising $43 million or 47% of this credit exposure, had credit quality less than investment grade, based on internal analysis.

Three of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase and 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 the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 2024 and 2023, there were $11 million and $12 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.

Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

As of Dec. 31, 2024 and 2023, there were approximately $63 million and $80 million of derivative liabilities with such underlying contract provisions, respectively.

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 a given utility subsidiary’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, 2024 and 2023.

Recurring Derivative Fair Value Measurements

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, 2024
Derivatives designated as cash flow hedges
Interest rate	$	16	$	—
Total	$	16	$	—
Other derivative instruments
Electric commodity	$	—	$	(18)
Natural gas commodity	—		2
Total	$	—	$	(16)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate	$	(3)	$	—
Total	$	(3)	$	—
Other derivative instruments
Electric commodity	$	—	$	(48)
Natural gas commodity	—		(1)
Total	$	—	$	(49)
Year Ended Dec. 31, 2022
Other derivative instruments
Electric commodity	$	—	$	(7)

Total	$	—	$	(7)

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	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, 2024
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	(10)	(b)
Electric commodity	—			21		(c)	—
Natural gas commodity	—			—			(7)		(d)(e)
Total	$	—		$	21		$	(17)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	(2)	(b)
Electric commodity	—			45		(c)	—
Natural gas commodity	—			—			(8)		(d)(e)
Total	$	—		$	45		$	(10)
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	17	(b)
Electric commodity	$	—		$	1	(c)	$	—
Natural gas commodity	—			2		(d)	(8)		(d)(e)
Total	$	—		$	3		$	9

(a)Recorded to interest charges.

(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.

(c)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. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between FTR auction and settlement dates, but exclude the original auction fair value.

(d)Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

(e)Relates primarily to option premium amortization.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2024, 2023 and 2022.

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Derivative assets and liabilities measured at fair value on a recurring basis were as follows:


	Dec. 31, 2024												Dec. 31, 2023
	Fair Value						Fair Value Total		Netting (a)		Total		Fair Value						Fair Value Total		Netting (a)		Total
(Millions of Dollars)	Level 1		Level 2		Level 3								Level 1		Level 2		Level 3
Current derivative assets
Other derivative instruments:
Commodity trading	$	5	$	20	$	8	$	33	$	(22)	$	11	$	7	$	32	$	32	$	71	$	(42)	$	29
Electric commodity	—		—		23		23		(2)		21		—		—		23		23		(7)		16
Natural gas commodity	—		4		—		4		—		4		—		5		—		5		—		5
Total current derivative assets	$	5	$	24	$	31	$	60	$	(24)	$	36	$	7	$	37	$	55	$	99	$	(49)	$	50


Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	3	$	33	$	47	$	83	$	(16)	$	67	$	7	$	43	$	45	$	95	$	(34)	$	61
Total noncurrent derivative assets	$	3	$	33	$	47	$	83	$	(16)	$	67	$	7	$	43	$	45	$	95	$	(34)	$	61



	Dec. 31, 2024												Dec. 31, 2023
	Fair Value						Fair Value Total		Netting (a)		Total		Fair Value						Fair Value Total		Netting (a)		Total
(Millions of Dollars)	Level 1		Level 2		Level 3								Level 1		Level 2		Level 3
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	7	$	—	$	7	$	—	$	7
Other derivative instruments:
Commodity trading	6		35		5		46		(22)		24		6		60		5		71		(43)		28
Electric commodity	—		—		1		1		(1)		—		—		—		7		7		(7)		—
Natural gas commodity	—		1		—		1		—		1		—		3		—		3		—		3
Total current derivative liabilities	$	6	$	36	$	6	$	48	$	(23)	25		$	6	$	70	$	12	$	88	$	(50)	38
PPAs (b)											6												6
Current derivative instruments											$	31											$	44
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	9	$	30	$	40	$	79	$	(18)	$	61	$	14	$	49	$	37	$	100	$	(36)	$	64
Total noncurrent derivative liabilities	$	9	$	30	$	40	$	79	$	(18)	61		$	14	$	49	$	37	$	100	$	(36)	64
PPAs (b)											16												22
Noncurrent derivative instruments											$	77											$	86

(a)NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2024 and 2023, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2024 and 2023, derivative assets and liabilities include rights to reclaim cash collateral of $1 million and $3 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

(b)NSP-Minnesota currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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Changes in Level 3 commodity derivatives:


	Year Ended Dec. 31
(Millions of Dollars)	2024		2023		2022
Balance at Jan. 1	$	51	$	107	$	56
Purchases (a)	72		98		157
Settlements (a)	(61)		(65)		(195)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)	(9)		15		91
Net losses recognized as regulatory assets and liabilities (a)	(21)		(104)		(2)
Balance at Dec. 31	$	32	$	51	$	107

(a)Relates primarily to FTR instruments administered by MISO.

(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the consolidated income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.

Fair Value of Long-Term Debt

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


	2024				2023
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	7,857	$	6,755	$	7,330	$	6,561
Long-term debt - related parties	166		99		—		—

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, 2024 and 2023, 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

Pension and Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Minnesota, has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits.

The average annual interest crediting rates for these plans was 4.89, 4.67 and 4.86% in 2024, 2023, and 2022, respectively.

Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. 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 who participated 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, 2024 and 2023 were $13 million and $12 million, respectively, of which an immaterial amount was attributable to NSP-Minnesota.

Xcel Energy’s postretirement health care benefit plan is a continuation of certain welfare benefit programs for current employees. A full-time employee’s date of hire or a retiree’s date of retirement determine eligibility for each of the programs.

Xcel Energy’s investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as the long-term projected return levels from investment experts. 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 2024 were below the assumed level of 7.25%.

•Investment returns in 2023 were above the assumed level of 7.25%.

•Investment returns in 2022 were below the assumed level of 6.60%.

•In 2025, NSP-Minnesota’s expected investment-return assumption is 7.25%.

Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’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.

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 consider many factors and generally 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

For each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value:


	Dec. 31, 2024 (a)										Dec. 31, 2023 (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	$	24	$	—	$	—	$	—	$	24	$	46	$	—	$	—	$	—	$	46
Commingled funds	—		—		—		373		373		110		—		—		265		375
Debt securities	—		123		1		—		124		—		127		1		—		128
Equity securities	6		—		—		—		6		8		—		—		—		8
Other	—		1		—		—		1		—		5		—		—		5
Total	$	30	$	124	$	1	$	373	$	528	$	164	$	132	$	1	$	265	$	562

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

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


	Dec. 31, 2024 (a)										Dec. 31, 2023 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total


Commingled funds	$	—	$	—	$	—	$	1	$	1	$	—	$	—	$	—	$	1	$	1
Debt securities	—		1		—		—		1		—		2		—		—		2

Total	$	—	$	1	$	—	$	1	$	2	$	—	$	2	$	—	$	1	$	3

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

Immaterial assets were transferred in or out of Level 3 for 2024. No assets were transferred in or out of Level 3 for 2023.

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)	2024		2023		2024		2023
Change in Benefit Obligation:
Obligation at Jan. 1	$	660	$	657	$	42	$	48
Service cost	22		21		1		—
Interest cost	34		36		2		3
Plan amendments	—		(1)		—		—
Actuarial (gain) loss	(22)		30		1		(2)

Benefit payments	(82)		(83)		(5)		(7)
Obligation at Dec. 31	$	612	$	660	$	41	$	42
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	562	$	570	$	3	$	5
Actual return on plan assets	7		52		—		—
Employer contributions	41		23		4		5

Benefit payments	(82)		(83)		(5)		(7)
Fair value of plan assets at Dec. 31	$	528	$	562	$	2	$	3
Funded status of plans at Dec. 31	$	(84)	$	(98)	$	(39)	$	(39)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Current liabilities	$	—	$	—	$	(3)	$	(2)
Noncurrent liabilities	(84)		(98)		(36)		(37)
Net amounts recognized	$	(84)	$	(98)	$	(39)	$	(39)


	Pension Benefits				Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:	2024		2023		2024		2023
Discount rate for year-end valuation	5.88	%	5.49	%	5.88	%	5.54	%
Expected average long-term increase in compensation level	4.25	%	4.25	%	N/A		N/A
Mortality table	PRI-2012		PRI-2012		PRI-2012		PRI-2012
Health care costs trend rate — initial: Pre-65	N/A		N/A		7.00	%	6.50	%
Health care costs trend rate — initial: Post-65	N/A		N/A		7.50	%	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		9		6

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Accumulated benefit obligation for the pension plan was $557 million and $599 million as of Dec. 31, 2024 and 2023, respectively.

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

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


	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2024			2023			2022			2024			2023			2022
Service cost	$	22		$	21		$	27		$	1		$	—		$	—
Interest cost	34			36			25			2			3			2
Expected return on plan assets	(46)			(46)			(48)			—			—			—
Amortization of prior service cost	—			—			—			—			(1)			(3)
Amortization of net loss	13			11			24			—			—			1
Settlement charge (a)	37			—			38			—			—			—
Net periodic pension cost	60			22			66			3			2			—
Effects of regulation	(30)			16			(32)			—			—			—
Net benefit cost recognized for financial reporting	$	30		$	38		$	34		$	3		$	2		$	—
Significant Assumptions Used to Measure Costs:
Discount rate	5.49		%	5.80		%	3.08		%	5.54		%	5.80		%	3.09		%
Expected average long-term increase in compensation level	4.25			4.25			3.75			—			—			—
Expected average long-term rate of return on assets	7.25			7.25			6.60			5.00			5.00			4.10

(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 2024 and 2022, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $37 million and $38 million, respectively, which was not recognized in earnings due to the effects of regulation. There were no settlement charges recorded for the qualified pension plans in 2023.


	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2024		2023		2024		2023
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	289	$	321	$	14	$	15

Total	$	289	$	321	$	14	$	15
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	$	14	$	11	$	—	$	—
Noncurrent regulatory assets	275		310		13		14

Net-of-tax accumulated other comprehensive income	—		—		1		1
Total	$	289	$	321	$	14	$	15

Measurement date	Dec 31, 2024		Dec 31, 2023		Dec 31, 2024		Dec 31, 2023

Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2022 - 2025 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

•$125 million in January 2025, of which $54 million is attributable to NSP-Minnesota.

•$100 million in 2024, of which $41 million was attributable to NSP-Minnesota.

•$50 million in 2023, of which $23 million was attributable to NSP-Minnesota.

•$50 million in 2022, of which $5 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. Xcel Energy’s voluntary postretirement funding contributions were as follows:

•$8 million expected in 2025, of which $5 million is attributable to NSP-Minnesota.

•$11 million during 2024, of which $4 million, was attributable to NSP-Minnesota.

•$11 million during 2023, of which $5 million was attributable to NSP-Minnesota.

•$13 million during 2022, of which $7 million was attributable to NSP-Minnesota.

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Targeted asset allocations:


	Pension Benefits				Postretirement Benefits
	2024		2023		2024		2023
Long-duration fixed income and interest rate swap securities	38	%	38	%	—	%	—	%
Domestic and international equity securities	31		31		25		9
Alternative investments	20		20		11		13
Short-to-intermediate fixed income securities	9		9		61		77
Cash	2		2		3		1
Total	100	%	100	%	100	%	100	%

The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.

Plan Amendments — There were no significant plan amendments made in 2024 and 2022 which affected the pension or postretirement benefit obligation.

In 2023, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental social security benefits for all active participants on and after Jan. 1, 2024.

Projected Benefit Payments

NSP-Minnesota’s projected benefit payments:


(Millions of Dollars)	Projected Pension Benefit Payments		Net Projected Postretirement Health Care Benefit Payments (a)
2025	$	63	$	5
2026	$	59	$	5
2027	58		4
2028	56		4
2029	57		4
2030-2034	269		15

(a)Amount is reported net of expected Medicare Part D subsidies, which are immaterial.

Voluntary Retirement Program

Incremental to amounts presented above for postretirement benefits, Xcel Energy, which includes NSP-Minnesota, recognized new postemployment costs and obligations in the fourth quarter of 2023 for employees accepted to a voluntary retirement program.

Utilizing employee information and the following inputs, unfunded obligations of $7 million and $8 million for health plan subsidies and $1 million and $1 million for other medical benefits are presented in other current liabilities and noncurrent pension and employee benefit obligations in the consolidated balance sheets as of Dec. 31, 2024 and 2023, respectively.


Significant Assumptions to Measure Benefit Obligations:	2024		2023
Discount rate for year-end valuation	5.00	%	5.50	%
Mortality table	PRI-2012		PRI-2012
Health care costs trend rate	7.00	%	7.00	%
Ultimate trend assumption	4.50	%	N/A
Years until ultimate trend is reached	9		N/A

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 $14 million, $14 million, and $13 million in 2024, 2023 and 2022, respectively.

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 pension plan, additional unfunded obligations may need to be funded over time by remaining participating employers.


10. Commitments and Contingencies

Legal

Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.

In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on NSP-Minnesota’s consolidated financial statements. Legal fees are generally expensed as incurred.

Rate Matters and Other

NSP-Minnesota is involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.

Sherco — In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA.

In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE.

In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota.

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In May 2024, the ALJ recommended a customer refund of $34 million (less a portion of the proceeds received from the settlement with GE). The ALJ indicated that consideration of the $22 million of previously disallowed costs was not in the scope of their recommendation. In 2024, following contested case procedures, the NSP-Minnesota recognized a customer refund of $47 million for replacement power incurred during the outage.

Minnesota 2023 Fuel Clause Adjustment — In March 2024, NSP-Minnesota filed its annual FCA true-up petition to the MPUC.

In 2024, the DOC recommended customer refunds for 2023 replacement power costs incurred during an outage at the Prairie Island generating station (October 2023 through February 2024). NSP-Minnesota estimates that customer refunds would be approximately $22 million if the DOC recommendations are applied to both 2023 and 2024.

In September 2024, the MPUC ruled NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in the extended outage. The MPUC did not quantify the refund and referred the determination of the refund amount to the Office of Administrative Hearings. NSP-Minnesota has recorded an estimated liability for a customer refund. The procedural schedule is as follows:

•Xcel Energy testimony: May 1, 2025

•Intervenor direct testimony: July 2, 2025

•Rebuttal testimony: August 13, 2025

•ALJ Report: March 16, 2026

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 and Disposal Sites

NSP-Minnesota is investigating, remediating or performing post-closure actions at seven MGP, landfill or other disposal sites across its service territories.

NSP-Minnesota has recognized approximately $1 million of costs/liabilities for resolution of these issues, however, the final outcome and timing are unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation — NSP-Minnesota is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste.

In May 2024, final amendments to the CCR Rule were published, widening its scope to include legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at CCR-regulated facilities, including areas of beneficial use.

As a requirement of the CCR Rule, utilities must complete facility evaluations and groundwater sampling around their subject landfills, surface impoundments and certain other areas where coal ash was placed on land.

If certain impacts to groundwater are detected, utilities may be required to perform additional groundwater investigations and/or perform corrective actions, typically beginning with an Assessment of Corrective Measures.

NSP-Minnesota expects to incur $6 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. AROs have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.

NSP-Minnesota has also identified coal ash that is expected to be required to be removed from certain closed coal-fueled generating facilities at estimated costs totaling approximately $60 million. AROs have been recorded, with the costs expected to be recoverable through regulatory mechanisms.

NSP-Minnesota continues to evaluate the 2024 updates to the CCR Rule, the interpretations of those updates and how they will apply to specific sites. Assessment of the recent updates to the CCR Rule and corresponding site investigation activities may result in updates to estimated costs as well as identification of additional required corrective actions.

Federal Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species.

NSP-Minnesota estimates capital expenditures of approximately $45 million may be required to comply with the requirements. NSP-Minnesota anticipates these costs will be recoverable through regulatory mechanisms.

Environmental Requirements — Air

Clean Air Act NOx Allowance Allocations — In June 2023, the EPA published final regulations under the "Good Neighbor" provisions of the Clean Air Act. The final rule applies to generation facilities in Minnesota, as well as other states outside of our service territory. The rule establishes an allowance trading program for NOx that will impact NSP-Minnesota’s fossil fuel-fired electric generating facilities. Applicable facilities will have to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations.

While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, NSP-Minnesota anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms. In June 2024, the U.S. Supreme Court issued an order granting a stay of the final rule. In response, the EPA issued a nationwide an administrative stay of the rule. Depending on the outcomes of the underlying legal challenges, the regulation may become applicable in the future.

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

Aggregate fair value of NSP-Minnesota’s legally restricted assets for funding future nuclear decommissioning was $3.5 billion and $3.2 billion at Dec. 31, 2024 and 2023, respectively.

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NSP-Minnesota’s AROs were as follows:


	2024
(Millions of Dollars)	Jan. 1, 2024		Amounts Incurred (a)		Amounts Settled		Accretion		Cash Flow Revisions (b)		Dec. 31, 2024
Electric
Nuclear	$	2,107	$	—	$	—	$	106	$	263	$	2,476
Wind	424		—		—		15		(33)		406
Steam and other production	77		61		(6)		4		3		139
Distribution	17		—		—		1		—		18
Natural gas
Transmission and distribution	32		—		—		2		(1)		33
Other
Miscellaneous	1		—		—		—		—		1
Total liability	$	2,658	$	61	$	(6)	$	128	$	232	$	3,073

(a)Amounts incurred pertain to CCR coal ash regulations and Sherco Solar 1 being placed in service.

(b)In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes in the nuclear AROs were driven by updated assumptions in the nuclear triennial filing coupled with discount rate and escalation rate changes. Wind, steam, and other production AROs were revised due to the results of 2024 dismantling studies.


	2023
(Millions of Dollars)	Jan. 1, 2023		Amounts Incurred (a)		Amounts Settled		Accretion		Cash Flow Revisions (b)		Dec. 31, 2023
Electric
Nuclear	$	2,160	$	—	$	—	$	105	$	(158)	$	2,107
Wind	416		10		—		15		(17)		424
Steam and other production	75		—		(1)		3		—		77
Distribution	16		—		—		1		—		17

Natural gas
Transmission and distribution	59		—		—		2		(29)		32
Other
Miscellaneous	1		—		—		—		—		1
Total liability	$	2,727	$	10	$	(1)	$	126	$	(204)	$	2,658

(a)Amounts incurred relate to the Northern Wind farm placed in service.

(b)In 2023, AROs were revised for changes in timing and estimates of cash flows. Changes in wind and nuclear AROs were primarily incurred due to changes in useful lives. Changes in gas transmission and distribution AROs were changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.

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, 2024. Therefore, an ARO has not been recorded for these facilities.

Nuclear Related

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $16.3 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $500 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $15.8 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.

NSP-Minnesota is subject to assessments of up to $166 million per reactor-incident for each of its three reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $25 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI for each of NSP-Minnesota’s two nuclear plant sites. The coverage limits are $2.8 billion for both Monticello and Prairie Island. NEIL also provides business interruption insurance coverage up to $490 million and $420 million at Monticello and Prairie Island, respectively, 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 $19 million for business interruption insurance and $34 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 Prairie Island 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. 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. In October 2023, a CON for additional storage at the Monticello site was approved by the MPUC to support extended operations to 2040.

The Prairie Island dry-cask storage facility currently stores 52 of the 64 authorized casks. In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054.

Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101.

NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for PI Unit 1 and 2034 for PI Unit 2. In February 2025, the MPUC approved a settlement agreement which extends the retirement dates for planning purposes to 2050, 2053, and 2054 for Monticello, PI Unit 1, and PI Unit 2, respectively. Requests to update the authorized retirement dates are expected to be submitted to the MPUC in 2025.

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 most recent triennial decommissioning study was filed in December 2024.

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Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $3.5 billion and $3.2 billion of assets held in external decommissioning trusts at Dec. 31, 2024, and 2023, respectively.

See Note 8 to the consolidated financial statements for additional discussion.

Leases

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

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

Most of NSP-Minnesota’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted average of 4.7%). For currently existing asset classes, NSP-Minnesota has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from lease payments for the purposes of lease accounting and disclosure.

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

Operating lease ROU assets:


(Millions of Dollars)	Dec. 31, 2024		Dec. 31, 2023
PPAs	$	709	$	709
Other	166		125
Gross operating lease ROU assets	875		834
Accumulated amortization	(482)		(395)
Net operating lease ROU assets	$	393	$	439

Components of lease expense:


(Millions of Dollars)	2024		2023		2022
Operating leases
PPA capacity payments	$	96	$	100	$	98
Other operating leases (a)	15		13		9
Total operating lease expense (b)	$	111	$	113	$	107

(a)Includes immaterial short-term lease expense for 2024, 2023 and 2022.

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

Commitments under operating leases as of Dec. 31, 2024:


(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases
2025	$	101	$	13	$	114
2026	89		13		102
2027	72		13		85
2028	40		13		53
2029	—		12		12
Thereafter	—		195		195
Total minimum obligation	302		259		561
Interest component of obligation	(22)		(125)		(147)
Present value of minimum obligation	$	280	$	134	414
Less current portion					(97)
Noncurrent operating lease liabilities					$	317

Weighted-average remaining lease term in years					11.9

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

(b)PPA operating leases contractually expire at various dates through 2039.

PPAs and Fuel Contracts

Non-Lease PPAs — NSP-Minnesota has entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, 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 may also include capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2041, contain minimum energy purchase commitments. Total energy payments on those contracts were $186 million, $185 million and $182 million in 2024, 2023 and 2022, respectively.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $64 million, $62 million and $60 million in 2024, 2023 and 2022, respectively.

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 financial results are mitigated through purchased energy cost recovery mechanisms.

At Dec. 31, 2024, 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)
2025	$	32	$	53
2026	15		21
2027	13		21
2028	6		22
2029	6		22
Thereafter	2		—
Total (b)	$	74	$	139

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

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

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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 2025 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities delivered under these agreements.

Estimated minimum purchases for these contracts as of Dec. 31, 2024:


(Millions of Dollars)	Coal		Nuclear fuel		Natural gas supply		Natural gas storage and transportation
2025	$	104	$	168	$	84	$	141
2026	40		62		—		140
2027	4		133		—		108
2028	—		19		—		41
2029	—		67		—		21
Thereafter	—		49		—		29
Total (a)	$	148	$	498	$	84	$	480

(a)Includes amounts allocated to NSP-Wisconsin through interchange billings.

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, however 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 NSP-Minnesota does not have the power to direct the activities that most significantly impact the entities’ economic performance.

NSP-Minnesota had approximately 1,347 MW of capacity under long-term PPAs at both Dec. 31, 2024 and 2023, with entities that have been determined to be VIEs. These agreements have expiration dates through 2039.


11. Other Comprehensive Income

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


	2024
(Millions of Dollars)	Gains and Losses on Interest Rate Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total
Accumulated other comprehensive loss at Jan. 1	$	(18)	$	(2)	$	(20)
Other comprehensive income before reclassifications	$	12	$	—	$	12




Accumulated other comprehensive loss at Dec. 31	$	(6)	$	(2)	$	(8)


	2023
(Millions of Dollars)	Gains and Losses on Interest Rate Cash Flow Hedges			Defined Benefit Pension and Postretirement Items		Total
Accumulated other comprehensive loss at Jan. 1	$	(16)		$	(2)	$	(18)
Other comprehensive loss before reclassifications	$	(3)		$	—	$	(3)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	1		(a)	—		1

Net current period other comprehensive income	(2)			—		(2)
Accumulated other comprehensive loss at Dec. 31	$	(18)		$	(2)	$	(20)

(a)Included in interest charges.


12. Segment Information

NSP-Minnesota is a wholly owned subsidiary of Xcel Energy. NSP-Minnesota’s chief operating decision maker, the CEO of Xcel Energy, sets financial performance objectives and budgets, with separate targets for regulated electric utility and regulated natural gas utility net income.

The regulated electric utility and regulated natural gas utility segments are managed separately because of inherent differences between activities to serve electric customers and those required to serve natural gas customers, and as the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. The CEO assesses financial performance, including quarterly and annual budget-to-actual and year-over-year variances in revenues and expenses, to inform operating decisions, capital investments and cost recovery strategies.

NSP-Minnesota has the following reportable segments:

•Regulated Electric Utility — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Minnesota, North Dakota and South Dakota; each state’s regulated electric utility activities qualify as an operating segment, and is aggregated into NSP-Minnesota’s regulated electric utility segment. 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 wholesale commodity and trading operations.

•Regulated Natural Gas Utility — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas primarily in portions of Minnesota and North Dakota; each state’s regulated natural gas utility activities qualify as an operating segment, and is aggregated into NSP-Minnesota’s regulated natural gas utility segment.

Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments. As an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment. 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.

Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

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Other segment expenses, net, for the reportable segments includes conservation and DSM expenses, taxes (other than income taxes), other income (expense), net, intersegment expenses and AFUDC - equity.

Non-segment revenues include appliance repair and non-utility real estate activities and revenues associated with processing solid waste into RDF. Non-segment net income also includes costs associated with these activities.

Segment information and reconciliations to NSP-Minnesota’s consolidated operating revenues and net income:


	2024
(Millions of Dollars)	Regulated electric utility		Regulated natural gas utility		Total segments
Operating revenues (a)	$	5,099	$	653	$	5,752
Intersegment revenue	1		11		12
Total segment revenues	5,100		664		5,764
Electric fuel and purchased power	1,988		—		1,988
Cost of natural gas sold and transported	—		295		295
O&M expenses	1,181		104		1,285


Depreciation and amortization	1,025		80		1,105
Other segment expenses, net	301		53		354
Interest charges and financing costs	307		30		337
Income tax (benefit) expense	(390)		25		(365)
Net income	$	688	$	77	$	765

Total segment revenues					$	5,764
Eliminate intersegment revenue					(12)
Non-segment revenues					15
Consolidated operating revenues					$	5,767

Total segment net income					$	765
Non-segment net income					28
Consolidated net income					$	793

(a)Regulated electric results include $460 million of affiliate revenues. Regulated natural gas results include $1 million of affiliate revenues. See Note 13 for further information.


	2023
(Millions of Dollars)	Regulated electric utility		Regulated natural gas utility		Total segments
Operating revenues (a)	$	5,241	$	754	$	5,995
Intersegment revenues	1		2		3
Total segment revenues	5,242		756		5,998
Electric fuel and purchased power	2,069		—		2,069
Cost of natural gas sold and transported	—		466		466
O&M expenses	1,153		98		1,251


Depreciation and amortization	909		71		980
Other segment expenses, net (b)	312		47		359
Interest charges and financing costs	278		26		304
Income tax (benefit) expense	(127)		10		(117)
Net income	$	648	$	38	$	686

Total segment revenues					$	5,998
Eliminate intersegment revenue					(3)
Non-segment revenues					48
Consolidated operating revenues					$	6,043

Total segment net income					$	686
Non-segment net income					21
Consolidated net income					$	707

(a)Regulated electric results include $493 million of affiliate revenues. Regulated natural gas results include $1 million of affiliate revenues. See Note 13 for further information.

(b)Other segment expenses, net, for 2023 additionally includes workforce reduction expenses.


	2022
(Millions of Dollars)	Regulated electric utility		Regulated natural gas utility		Total segments
Operating revenues (a)	$	5,617	$	1,022	$	6,639
Intersegment revenues	1		2		3
Total segment revenues	5,618		1,024		6,642
Electric fuel and purchased power	2,416		—		2,416
Cost of natural gas sold and transported	—		741		741
O&M expenses	1,126		94		1,220


Depreciation and amortization	953		60		1,013
Other segment expenses, net	367		48		415
Interest charges and financing costs	257		22		279
Income tax (benefit) expense	(127)		14		(113)
Net income	$	626	$	45	$	671

Total segment revenues					$	6,642
Eliminate intersegment revenue					(3)
Non-segment revenues					45
Consolidated operating revenues					$	6,684

Total segment net income					$	671
Non-segment net income					4
Consolidated net income					$	675

(a)Regulated electric results include $514 million of affiliate revenues. See Note 13 for further information.

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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, NSP-Wisconsin, 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)	2024		2023		2022
Operating revenues:
Electric	$	460	$	493	$	514
Gas	1		1		—
Operating expenses:
Purchased power	65		63		70
Transmission expense	151		142		132
Other operating expenses — paid to Xcel Energy Services Inc.	710		719		673
Interest income	5		1		1
Interest expense	2		5		1

Accounts receivable and payable with affiliates at Dec. 31:


	2024				2023
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Wisconsin	$	—	$	28	$	9	$	—
PSCo	—		7		5		—
SPS	—		2		—		4
Other subsidiaries of Xcel Energy Inc.	1		63		1		85
	$	1	$	100	$	15	$	89

During 2024, Xcel Energy Inc. repurchased certain of NSP-Minnesota’s first mortgage bonds. For more information about these repurchases, see Note 5.


14. Workforce Reduction

In 2023, Xcel Energy implemented workforce actions to align resources and investments with evolving business and customer needs, and streamline the organization for long-term success.

In September 2023, Xcel Energy announced a voluntary retirement program to a group of eligible non-bargaining employees, with an enhanced retirement package including certain health care and cash benefits for accepted employees. Approximately 400 employees retired under this program in December 2023.

In November 2023, Xcel Energy, Inc. also reduced its non-bargaining workforce by approximately 150 employees through an involuntary severance program.

In the fourth quarter of 2023, Xcel Energy recorded total expense of $72 million related to these workforce actions, of which $32 million was attributable to NSP-Minnesota. Expenses relate to the estimated cost of future health plan subsidies and other medical benefits for the voluntary retirement program, as well as severance and other employee payouts and legal and other professional fees.

No such activities occurred in 2024.

For further information on the estimated obligations for future health plan subsidies and other medical benefits, see Note 9 to the consolidated financial statements.


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 CEO and CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, 2024, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No changes in NSP-Minnesota’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2024 that materially affected, or are 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, 2024 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, as approved by the SEC and as indicated in NSP-Minnesota’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.

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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.


ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

Items 10, 11 and 12 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 definitive Proxy Statement for its 2025 Annual Meeting of Shareholders, which is incorporated by reference.


ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required under this Item (aggregate fees billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is contained in Xcel Energy Inc.’s Proxy Statement for its 2025 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV


ITEM 15 — EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


1			Consolidated Financial Statements:
			Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2024.
			Report of Independent Registered Public Accounting Firm — Financial Statements
			Consolidated Statements of Income — For each of the three years ended Dec. 31, 2024, 2023 and 2022.
			Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2024, 2023 and 2022.
			Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2024, 2023 and 2022.
			Consolidated Balance Sheets — As of Dec. 31, 2024 and 2023.
			Consolidated Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2024, 2023 and 2022.

2			Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2024, 2023 and 2022.

3			Exhibits

*			Indicates incorporation by reference
+			Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors


Exhibit Number	Description	Report or Registration Statement	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	3.01
3.02*	By-Laws of NSP-Minnesota as Amended and Restated on Jan. 25, 2019	NSP-Minnesota Form 10-K for the year ended Dec. 31, 2018	3.02
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	4(b)(3)
4.02*	Supplemental Trust Indenture, dated as of June 1, 1995, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, creating $250 million aggregate 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	4.11
4.03*	Supplemental Trust Indenture, dated as of March 1, 1998, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, creating $150 million aggregate 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	4.12
4.04*	Supplemental Trust Indenture, dated as of Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)	NSP-Minnesota Form 10-12G dated Oct. 5, 2000	4.51
4.05*	Supplemental Trust Indenture, dated as of July 1, 2005, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $250 million aggregate principal amount of 5.25% First Mortgage Bonds, Series due July 15, 2035	NSP-Minnesota Form 8-K dated July 14, 2005	4.01
4.06*	Supplemental Trust Indenture, dated as of May 1, 2006, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $400 million aggregate principal amount of 6.25% First Mortgage Bonds, Series due June 1, 2036	NSP-Minnesota Form 8-K dated May 18, 2006	4.01

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4.07*	Supplemental Trust Indenture, dated as of June 1, 2007, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $350 million aggregate principal amount of 6.20% First Mortgage Bonds, Series due July 1, 2037	NSP-Minnesota Form 8-K dated June 19, 2007	4.01
4.08*	Supplemental Trust Indenture, dated as of Nov. 1, 2009, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company., NA, as Trustee, creating $300 million aggregate principal amount of 5.35% First Mortgage Bonds, Series due Nov. 1, 2039	NSP-Minnesota Form 8-K dated Nov. 16, 2009	4.01
4.09*	Supplemental Trust Indenture, dated as of Aug. 1, 2010, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as Trustee, creating $250 million aggregate principal amount of 4.85% First Mortgage Bonds, Series due Aug. 15, 2040	NSP-Minnesota Form 8-K dated Aug. 4, 2010	4.01
4.10*	Supplemental Trust Indenture, dated as of Aug. 1, 2012, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as Trustee, creating $500 million aggregate principal amount of 3.40% First Mortgage Bonds, Series due Aug. 15, 2042	NSP-Minnesota Form 8-K dated Aug. 13, 2012	4.01
4.11*	Supplemental Trust Indenture, dated as of May 1, 2014, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.125% First Mortgage Bonds, Series due May 15, 2044	NSP-Minnesota Form 8-K dated May 13, 2014	4.01
4.12*	Supplemental Trust Indenture, dated as of Aug. 1, 2015, by and between NSP-Minnesota and The Bank of New York Mellon Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.00% First Mortgage Bonds, Series due Aug. 15, 2045	NSP-Minnesota Form 8-K dated Aug. 11, 2015	4.01
4.13*	Supplemental Trust Indenture, dated as of May 1, 2016, by and between NSP-Minnesota and The Bank of NY Mellon Trust Company, N.A., as Trustee, creating $350 million aggregate principal amount of 3.60% First Mortgage Bonds, Series due May 15, 2046	NSP-Minnesota Form 8-K dated May 31, 2016	4.01
4.14*	Supplemental Trust Indenture, dated as of Sept. 1, 2017, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 3.60% First Mortgage Bonds, Series due Sept. 15, 2047	NSP-Minnesota Form 8-K dated Sept. 13, 2017	4.01
4.15*	Supplemental Trust Indenture, dated as of Sept. 1, 2019, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 2.90% First Mortgage Bonds, Series due March 1, 2050	NSP-Minnesota Form 8-K dated Sept. 10, 2019	4.01
4.16*	Supplemental Indenture, dated as of June 8, 2020, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $700 million aggregate principal amount of 2.60% First Mortgage Bonds, Series due June 1, 2051	NSP-Minnesota 8-K dated June 15, 2020	4.01
4.17*	Supplemental Indenture, dated as of March 1, 2021, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $425 million principal amount of 2.25% First Mortgage Bonds, Series due April 1, 2031 and $425 million principal amount of 3.20% First Mortgage Bonds, Series due April 1, 2052	NSP-Minnesota 8-K dated March 30, 2021	4.01
4.18*	Supplemental Indenture, dated as of May 1, 2022, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $500 million aggregate principal amount of 4.50% First Mortgage Bonds, Series due June 1, 2052	NSP-Minnesota 8-K dated May 9, 2022	4.01
4.19*	Supplemental Trust Indenture dated as of May 1, 2023 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $800 million aggregate principal amount of 5.10% First Mortgage Bonds, Series due May 15, 2053.	NSP-Minnesota 8-K dated May 8, 2023	4.01
4.20*	Supplemental Trust Indenture dated as of February 1, 2024 between Northern States Power Company and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $700,000,000 aggregate principal amount of 5.40% First Mortgage Bonds, Series due March 15, 2054.	NSP-Minnesota 8-K dated Feb. 29, 2024	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	10.02
10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.05
10.03*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.18
10.04*+	Fifth Amendment to Exhibit 10.02 dated May 3, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016	10.01
10.05*+	Seventh Amendment to Exhibit 10.02 dated May 7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	10.01
10.06*+	Eighth Amendment to Exhibit 10.02 dated March 31, 2020	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020	10.02
10.07*+	Ninth Amendment to Exhibit 10.02 dated May 22, 2020	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020	10.01
10.08+	Tenth Amendment to Exhibit 10.02 dated May 20, 2024
10.09*+	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	10.17



10.10*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.07
10.11*+	First Amendment to Exhibit 10.10 effective Nov. 29, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.17
10.12*+	Second Amendment to Exhibit 10.10 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	10.22
10.13*+	Third Amendment to Exhibit 10.10 dated Sept. 30, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016	10.01
10.14*+	Fourth Amendment to Exhibit 10.10 dated Oct. 23, 2017	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017	10.1
10.15*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.34
10.16*+	Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards between 2020-2023	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019	10.35

Table of Contents


10.17*+	Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards in 2024	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023	10.16
10.18*+	Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated Dec. 10, 2021	10.01
10.19*+	Xcel Energy Inc. Annual Incentive Plan, effective Feb. 21, 2024	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023	10.18
10.20*+	Summary of Non-Employee Director Compensation, effective as of May 24, 2023	Xcel Energy Inc. Form 8-K dated Jan. 20, 2025	10.01
10.21*+	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	Appendix A
10.22*+	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	10.36
10.23*+	Xcel Energy Inc. 2024 Equity Incentive Plan	Xcel Energy Inc. Form S-8 dated May 22, 2024	4.01
10.24*+	Xcel Energy Inc. Stock Program for Non-Employee Directors (Effective May 22, 2024) under the 2024 Equity Incentive Plan	Xcel Energy Inc. Form 8-K dated May 22, 2024	10.01
10.25+	Form of Award Agreement for Restricted Stock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan for awards since 2025
10.26+	Form of Award Agreement for Performance S tock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan for awards since 2025
10.27*+	Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan	Xcel Energy Inc. Form 8-K dated May 22, 2024	10.03
10.28*+	Form of Award Agreement for Restricted Stock under the Xcel Energy Inc. 2024 Equity Incentive Plan	Xcel Energy Inc. Form 8-K dated May 22, 2024	10.04
10.29*	Form of Services Agreement between Xcel Energy Services Inc. and utility companies	Xcel Energy Inc. Form U5B dated Nov. 16, 2000	H-1
10.30+	Aircraft Time Sharing Agreement, effective Feb. 25, 2025, between Xcel Energy Services Inc., as Operator, and the Chief Executive Officer of Operator
10.31*	Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota	NSP-Wisconsin Form S-4 dated Jan.21, 2004	10.01
10.31*	Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, 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 Citibank, N.A., MUFG Bank, Ltd., and Wells Fargo Bank, National Association, as Documentation Agents	Xcel Energy Inc. Form 8-K dated Sept. 19, 2022	99.02
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.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

SCHEDULE II

NSP-Minnesota and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31


	Allowance for bad debts
(Millions of Dollars)	2024		2023		2022
Balance at Jan. 1	$	48	$	46	$	45
Additions charged to costs and expenses	21		30		21
Additions charged to other accounts (a)	7		6		6
Deductions from reserves (b)	(34)		(34)		(26)
Balance at Dec. 31	$	42	$	48	$	46

(a)Recovery of amounts previously written-off.

(b)Deductions related 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. 27, 2025						/s/ BRIAN J. VAN ABEL
						Brian J. Van Abel
						Executive Vice President, Chief Financial Officer and Director

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/ ROBERT C. FRENZEL						/s/ RYAN J. LONG
Robert C. Frenzel						Ryan J. Long
Chairman, Chief Executive Officer and Director						President and Director
(Principal Executive Officer)

/s/ BRIAN J. VAN ABEL						/s/ MELISSA L. OSTROM
Brian J. Van Abel						Melissa L. Ostrom
Executive Vice President, Chief Financial Officer and Director						Senior Vice President, Controller
(Principal Financial Officer)						(Principal Accounting Officer)

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.