XCEL ENERGY INC (XEL)

CIK: 0000072903. SIC: 4931 Electric & Other Services Combined. Latest 10-K as of: 2026-02-25.

SIC breadcrumb: Transportation, Communications, Electric, Gas, And Sanitary Services > Electric, Gas, And Sanitary Services > SIC 4931 Electric & Other Services Combined

SEC company page: https://www.sec.gov/edgar/browse/?CIK=72903. Latest filing source: 0000072903-26-000009.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-25. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000072903.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-25. Report date: 2025-12-31.

ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 ROE, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP.

Xcel Energy’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.

Ongoing ROE

Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholders’ equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.

Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)

GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.

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

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

(Millions of Dollars)

2025

2024

GAAP net income

$

2,018 

$

1,936 

Sherco Unit 3 2011 outage refunds

— 

47 

Marshall Wildfire litigation (a)

298 

— 

Less: tax effect of adjustments

(77)

(13)

Ongoing earnings (b)

$

2,239 

$

1,969 

(a)Includes $2 million of interest costs associated with short-term debt used to pay settlement, which is presented as interest expense on the consolidated statements of income.

(b)Amounts may not add due to rounding.

Twelve Months Ended Dec. 31, 2025

Diluted Earnings (Loss)

Per Share

GAAP Diluted EPS

Impact of Adjustments

Ongoing Diluted EPS

NSP-Minnesota

$

1.53 

$

— 

$

1.53 

PSCo

1.15 

0.38 

1.53 

SPS

0.67 

— 

0.67 

NSP-Wisconsin

0.27 

— 

0.27 

Earnings from equity method investments — WYCO

0.03 

— 

0.03 

Regulated utility (a)

3.65 

0.38 

4.03 

Xcel Energy Inc. and Other

(0.23)

— 

(0.23)

Total (a)

$

3.42 

0.38 

$

3.80 

Twelve Months Ended Dec. 31, 2024

Diluted Earnings (Loss)

Per Share

GAAP Diluted EPS

Impact of Adjustments

Ongoing Diluted EPS

NSP-Minnesota

$

1.41 

$

0.06 

$

1.47 

PSCo

1.39 

— 

1.39 

SPS

0.70 

— 

0.70 

NSP-Wisconsin

0.24 

— 

0.24 

Earnings from equity method investments — WYCO

0.03 

— 

0.03 

Regulated utility (a)

3.76 

0.06 

3.83 

Xcel Energy Inc. and Other

(0.33)

— 

(0.33)

Total (a)

$

3.44 

0.06 

$

3.50 

(a)Amounts may not add due to rounding.

Adjustments to GAAP net income include:

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 October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage, which is presented as a non-recurring charge to electric revenues.

Marshall Wildfire Litigation — In the third quarter of 2025, PSCo recognized a non-recurring $287 million charge as a result of a settlement reached with the plaintiffs in the Marshall Wildfire litigation. In the fourth quarter of 2025, an additional $12 million was recognized for estimated remaining settlement costs as well as legal and other costs.

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Results of Operations

Diluted EPS for Xcel Energy at Dec. 31:

Diluted Earnings (Loss) Per Share

2025

2024

NSP-Minnesota

$

1.53 

$

1.41 

PSCo

1.15 

1.39 

SPS

0.67 

0.70 

NSP-Wisconsin

0.27 

0.24 

Earnings from equity method investments — WYCO

0.03 

0.03 

Regulated utility (a)

3.65 

3.76 

Xcel Energy Inc. and Other

(0.23)

(0.33)

GAAP diluted EPS (a)

$

3.42 

$

3.44 

Sherco Unit 3 2011 outage refunds

— 

0.06 

Marshall Wildfire settlement

0.38 

— 

Ongoing diluted EPS (a)

$

3.80 

$

3.50 

(a)Amounts may not add due to rounding.

Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.

2025 Comparison with 2024

Xcel Energy — GAAP diluted earnings were $3.42 per share compared to $3.44 per share in 2024 and ongoing diluted earnings were $3.80 per share in 2025, compared with $3.50 per share in 2024. The change in ongoing EPS was driven by increased recovery of infrastructure investments and electric sales growth, partially offset by higher interest, depreciation and O&M expenses.

Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

NSP-Minnesota — GAAP earnings increased $0.12 per share and ongoing earnings increased $0.06 per share for 2025 compared to 2024. Ongoing earnings increased due to higher recovery of electric infrastructure investments, partially offset by increased O&M expenses, depreciation and interest charges.

PSCo — GAAP earnings decreased $0.24 per share and ongoing earnings increased $0.14 per share for 2025 (difference in GAAP and ongoing due to Marshall Wildfire settlement in 2025, see Non-GAAP Financial Measures for reconciliation from GAAP to ongoing earnings). Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments and increased AFUDC, which was partially offset by increased depreciation, interest and O&M charges.

SPS — GAAP and ongoing earnings decreased $0.03 per share for 2025 . The decrease was driven by increased interest charges, O&M expenses and the negative impact of weather, partially offset by sales growth and higher recovery of electric infrastructure investments.

NSP-Wisconsin — GAAP and ongoing earnings increased $0.03 per share for 2025. The increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and O&M expenses.

Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The change in earnings was due to gains on debt repurchases, partially offset by higher interest rates and debt levels.

Changes in Diluted EPS

Components significantly contributing to changes in 2025 EPS compared with 2024:

Diluted Earnings (Loss) Per Share

Twelve Months Ended Dec. 31

GAAP diluted EPS — 2024

$

3.44 

Components of change — 2025 vs. 2024

Higher electric revenues

1.27 

Higher natural gas revenues

0.29 

Higher AFUDC equity & debt

0.27 

Marshall Wildfire settlement

(0.38)

Higher interest charges

(0.28)

Higher depreciation and amortization

(0.28)

Higher O&M expenses

(0.25)

Higher electric fuel and purchased power (a)

(0.23)

Common equity financing

(0.18)

Higher costs of natural gas sold and transported (a)

(0.12)

Other, net

(0.13)

GAAP diluted EPS — 2025

$

3.42 

Marshall Wildfire settlement

0.38 

Ongoing diluted EPS — 2025

$

3.80 

(a)Cost of electric fuel and purchased power and natural gas sold and transported are generally recovered through regulatory recovery mechanisms and offset in revenue.

ROE for Xcel Energy and its utility subsidiaries:

2025

2024

ROE

GAAP ROE

Ongoing ROE

GAAP ROE

Ongoing ROE

NSP-Minnesota

9.19 

%

9.19 

%

9.07 

%

9.46 

%

PSCo

5.66 

7.55 

7.63 

7.63 

SPS

8.70 

8.70 

9.57 

9.57 

NSP-Wisconsin

9.09 

9.09 

8.98 

8.98 

Utility Subsidiaries

7.60 

8.40 

8.55 

8.69 

Xcel Energy

9.36 

10.38 

10.42 

10.61 

Statement of Income Analysis

The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.

Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements.

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As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. Gas decoupling mechanisms (and electric sales true-up in 2024) in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.

Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.

Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.

Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.

Percentage increase (decrease) in normal and actual HDD, CDD and THI:

2025 vs.

Normal

2024 vs.

Normal

2025 vs. 2024

HDD

(6.2)

%

(15.4)

%

8.7 

%

CDD

(4.9)

28.1 

(23.5)

THI

11.2 

(11.2)

26.8 

Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:

2025 vs. Normal

2024 vs. Normal

2025 vs. 2024

Retail electric

$

(0.015)

$

(0.008)

$

(0.007)

Decoupling and sales true-up

— 

0.047 

(0.047)

Electric total

$

(0.015)

$

0.039 

$

(0.054)

Firm natural gas

(0.033)

(0.070)

0.037 

Decoupling

0.005 

0.027 

(0.022)

Gas total

$

(0.028)

$

(0.043)

$

0.015 

Total

$

(0.043)

$

(0.004)

$

(0.039)

Sales — Sales growth (decline) for actual and weather-normalized sales:

2025 vs. 2024

NSP-Minnesota

PSCo

SPS

NSP-Wisconsin

Xcel Energy

Actual

Electric residential

5.7 

%

(1.6)

%

(1.5)

%

6.0 

%

1.9 

%

Electric C&I

0.3 

0.1 

5.5 

0.7 

2.0 

Total retail electric sales

2.0 

(0.5)

4.2 

2.2 

1.9 

Firm natural gas sales

12.6 

(2.1)

N/A

16.2 

3.4 

2025 vs. 2024

NSP-Minnesota

PSCo

SPS

NSP-Wisconsin

Xcel Energy

Weather-normalized

Electric residential

1.3 

%

1.4 

%

3.9 

%

1.7 

%

1.7 

%

Electric C&I

(0.6)

1.4 

6.1 

0.1 

2.1 

Total retail electric sales

— 

1.3 

5.6 

0.6 

2.0 

Firm natural gas sales

— 

(2.9)

N/A

2.0 

(1.7)

2025 vs. 2024 (Leap Year Adjusted)

NSP-Minnesota

PSCo

SPS

NSP-Wisconsin

Xcel Energy

Weather-normalized

Electric residential

1.5 

%

1.7 

%

4.3 

%

2.1 

%

2.0 

%

Electric C&I

(0.3)

1.6 

6.3 

0.4 

2.4 

Total retail electric sales

0.3 

1.6 

5.8 

0.9 

2.2 

Firm natural gas sales

0.6 

(2.4)

N/A

2.6 

(1.2)

Annual weather-normalized and leap year adjusted electric sales growth (decline)

•NSP-Minnesota — Residential sales increased due to customer growth (1.1%) and use per customer (0.4%). The decrease in C&I sales was due to lower use per customer.

•PSCo — Residential sales increased due to customer growth (1.1%) and use per customer (0.6%). The increase in C&I sales was due to higher use per customer, particularly in the information and energy sectors.

•SPS — Residential sales increased due to increased use per customer (3.6%) and customer growth (0.7%). The increase in C&I sales was due to higher use per customer, primarily driven by the energy sector.

•NSP-Wisconsin — Residential sales increased due to increased use per customer (1.1%) and customer growth (0.9%). The increase in C&I sales was due to customer growth.

Annual weather-normalized and leap year adjusted natural gas sales growth (decline)

•Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential and C&I, partially offset by customer growth in all jurisdictions.

Electric Revenues

Electric revenues are impacted by 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.

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Table of Contents     

(Millions of Dollars)

2025 vs. 2024

Non-fuel riders

$

250 

Recovery of higher cost of electric fuel and purchased power

214 

PTCs flowed back to customers (offset by lower ETR)

172 

Regulatory rate outcomes (MN, ND)

116 

Sales and demand

97 

Transmission revenues

79 

Sherco Unit 3 2011 outage refunds

47 

Estimated impact of weather

(39)

Conservation and demand side management (offset in expense)

(38)

Other, net

115 

Total increase

$

1,013 

Natural Gas Revenues

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

(Millions of Dollars)

2025 vs. 2024

Recovery of higher cost of natural gas

$

92 

Regulatory rate outcomes (CO)

84 

Conservation revenue (offset in expense)

47 

Estimated impact of weather (net of decoupling)

11 

Retail sales decline (net of decoupling)

(13)

Other, net

1 

Total increase

$

222 

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, 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 increased $173 million in 2025. The increase is primarily due to increased commodity prices and transmission expense.

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 increased $90 million in 2025. The increase is primarily due to increased commodity prices and volumes, partially offset by timing of fuel recovery mechanisms.

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $192 million in 2025 primarily due to increased benefits and healthcare costs, wildfire mitigation (largely offset in non-fuel rider revenue), nuclear generation costs and insurance costs.

Depreciation and Amortization — Depreciation and amortization increased $209 million for the year, primarily related to system investment.

Other Income — Other income increased $92 million for the year, primarily related to gains on debt repurchases.

Interest Charges — Interest charges increased $213 million in 2025. The increase was largely due to higher long-term and short-term debt levels and higher interest rates.

AFUDC, Equity and Debt — AFUDC increased $165 million in 2025, due to system investment.

Xcel Energy Inc. and Other Results

Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:

(Millions of Dollars)

2025

2024

Xcel Energy Inc. financing costs

$

(271)

$

(223)

Xcel Energy Inc. other results (a)

135 

38 

Total Xcel Energy Inc. and other

$

(136)

$

(185)

(Diluted Earnings (Loss) Per Share)

2025

2024

Xcel Energy Inc. financing costs

$

(0.46)

$

(0.40)

Xcel Energy Inc. other results (a)

0.23 

0.07 

Total Xcel Energy Inc. and other costs

$

(0.23)

$

(0.33)

(a)Amounts primarily include gains from debt repurchases, partially offset by taxes.

Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.

2024 Comparison with 2023

A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2023 to Dec. 31, 2024 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2024, which was filed with the SEC on Feb. 27, 2025. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

Public Utility Regulation

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. Xcel Energy 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, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.

Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’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 Xcel Energy’s results of operations and credit quality.

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

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Table of Contents     

NSP-Minnesota

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 no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales 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

Returns benefits and recovers costs from investments benefiting customers in South Dakota.

Natural Gas Innovation Act Rider

Recovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.

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 for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.

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.

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

2025 Minnesota Natural Gas Rate Case — In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026.

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.

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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. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026.

2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota 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. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million.

In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations.

In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota’s proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%.

An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.

2025 South Dakota Electric Rate Case — In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.

The procedural schedule is as follows:

•Intervenor direct testimony: March 20, 2026

•Rebuttal testimony: April 14, 2026

•Evidentiary Hearing: April 28-30, 2026

A SDPUC decision is expected in the first half of 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 $45 million (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).

In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%.

2026 North Dakota Natural Gas Rate Case — In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026.

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, and 2054 for Prairie Island.

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.

NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal 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.

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NSP-Wisconsin

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

Additional Information

PSCW

Retail rates, services and other aspects of electric and natural gas operations.

Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.

The PSCW has a biennial base rate filing requirement. By April of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.

Pipeline safety compliance.

MPSC

Retail rates, services and other aspects of electric and natural gas operations.

Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.

Pipeline safety compliance.

FERC

Wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.

MISO

NSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.

DOT

Pipeline safety compliance.

Recovery Mechanisms

Mechanism

Additional Information

Annual Fuel Cost Plan

NSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.

Natural Gas Cost-Recovery Factor (MI)

NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.

Power Supply Cost Recovery Factors

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.

Purchased Gas Adjustment (WI)

A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation and storage services.

Pending Regulatory Proceedings

Excess Liability Insurance Deferral – In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal. The PSCW issued a written approval in November 2025 and authorized recovery of the deferral over 2026 and 2027 in the Wisconsin Electric and Natural Gas Rate Case described below.

Wisconsin Electric and Natural Gas Rate Case – In March 2025, NSP-Wisconsin filed a request with the PSCW for a multi-year electric and natural gas rate increase. Both the electric and natural gas rate requests were based on forward-looking 2026 and 2027 test years, with a 10.0% ROE and an equity ratio of 53.5%.

In December 2025, the PSCW issued final written approval on NSP-Wisconsin’s request, with a final rate increase of $126 million for the electric utility ($68 million in 2026, with an incremental $58 million in 2027) and $22 million for the natural gas utility ($18 million in 2026, with an incremental $4 million in 2027), based on a ROE of 9.8% and an equity ratio of 52.5%.

(Millions of Dollars)

Electric

Natural Gas

NSP-Wisconsin’s filed two-year rate request

$

151 

$

24 

PSCW decision:

Capital investments

(8)

(1)

ROE adjustment

(7)

(1)

O&M expenses

(5)

(1)

Nuclear decommissioning accrual update (a)

(6)

—

Excess liability insurance deferral recovery

4 

1

Other, net

(3)

—

Total revenue change

$

126 

$

22 

(a)Since filing the case, the MPUC authorized a reduction to the annual nuclear decommissioning accrual. This reduction, which flows to NSP-Wisconsin through the interchange agreement, reduced the NSP-Wisconsin rate request and is earnings neutral.

Michigan Natural Gas Rate Case – In July 2025, NSP-Wisconsin filed a natural gas rate case in Michigan, seeking a revenue increase of $2.2 million. In December 2025, the MPSC issued a final written approval of the settlement order, with a final rate increase of $1.6 million ($0.7 million in 2026, with an incremental $0.9 million in 2027) based on a ROE of 9.8% and an equity ratio of 50%.

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NSP System

Pending and Recently Concluded Regulatory Proceedings

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 early 2026.

•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. NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025. NSP-Minnesota filed for requisite approvals of the selected resources with the MPUC in the fourth quarter of 2025 (decision expected in early 2026); NSP-Wisconsin expects to file for approvals with the PSCW in 2026.

•In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued an RFP seeking up to 3,500 MW of wind, solar, hydro, standalone storage, or hybrid capacity that will achieve commercial operation by December 31, 2030. Additionally, NSP-Minnesota is seeking to procure up to 600 MW of solar or solar + storage capacity that will achieve commercial operation by December 31, 2029, and meet Minnesota’s Distributed Solar Energy Standard eligibility requirements. Bids are due in March 2026, and filing for MPUC approval is expected by the end of 2026, ahead of the established procedural schedule.

•NSP-Minnesota and NSP-Wisconsin may continue to file additional RFPs throughout 2026 and 2027 for resource needs as part of its Upper Midwest resource planning efforts.

Large Load Agreement — In the first quarter of 2026, NSP-Minnesota entered into an electric service agreement to power a new Google data center in Minnesota. Under the agreement, Google will pay all costs for its new service for the duration of the agreement, in accordance with Minnesota’s regulatory and legislative requirements for large loads. Requests for approval of the Electric Service Agreement and 1,900 MW of proposed renewable generation to support the data center is expected to be filed with the MPUC by April 2026.

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.

PSCo

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

Additional Information on Regulatory Authority

CPUC

Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.

Reviews and approves Integrated Resource Plans for meeting future energy needs.

Certifies the need and siting for generating plans greater than 50 MW.

Pipeline safety compliance.

FERC

Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.

Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area.

PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.

RTO

PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.

DOT

Pipeline safety compliance.

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Recovery Mechanisms

Mechanism

Additional Information

Colorado Energy Plan Adjustment

Recovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill.

Clean Energy Plan Revenue

Recovers projects approved through the Clean Energy Plan to a maximum of 1.25% of the customer’s bill.

DSM Cost Adjustment

Recovers electric and gas DSM and CHP, interruptible service costs and performance incentives for achieving energy savings goals.

Electric Commodity Adjustment

Recovers fuel, purchased energy costs and certain owned renewable generating assets. Short-term sales margins are shared with customers. PTCs earned for owned wind and solar generation are returned to customers.

FCA

PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.

GCA

Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. Gas Price Risk Management Plan reserves are also collected in this mechanism as gas prices permit.

GMAC

Recovers select categories of distribution costs.

Purchased Capacity Cost Adjustment

Recovers purchased capacity payments.

RES Adjustment

Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.

Steam Cost Adjustment

Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.

Transmission Cost Adjustment

Recovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric distribution retail revenues, respectively.

Transportation Electrification Plan

Recovers costs associated with the investment in and adoption of transportation electrification infrastructure.

Wildfire Mitigation Adjustment

Recovers actual 2025-2027 costs associated with wildfire mitigation.

Pending and Recently Concluded Regulatory Proceedings

2025 Colorado Electric Rate Case — In November 2025, PSCo filed an electric rate case with the CPUC seeking an increase in revenue of $356 million (9.9%) ($526 million inclusive of rider roll-ins). The request is based on a 9.8% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $13 billion.

PSCo’s base rate request (millions of dollars):

Distribution system investment

$

294 

Liability insurance

65 

Operating costs

51 

Changes in cost of capital

49 

Coal retirements (a)

(120)

Other

17 

Rate request, net of rider roll-ins

$

356 

(a)The case includes request for rider recovery of any costs associated with extending operations at Comanche Unit 2.

A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.

2025 Colorado Natural Gas Rate Case — In December 2025, PSCo filed a natural gas rate case with the CPUC seeking an increase in revenue of $190 million (11.6%). The request is based on a 10.75% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $4.7 billion.

PSCo’s base rate request (millions of dollars):

Capital investments

$

90 

Changes in cost of capital

53 

Operating costs

42 

Sales/revenue growth

(7)

Other

12 

Total rate request

$

190 

A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.

2024 Colorado Natural Gas Rate Case — In January 2024, PSCo filed a natural gas rate case with the CPUC. In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including an annual revenue increase of approximately $125 million, inclusive of $15 million of accelerated depreciation.

In May 2025, PSCo filed an appeal with the Denver District Court seeking review of the CPUC’s decisions related to recovery of certain operating expenses, cost of capital and capital structure, and the treatment of gas storage inventory costs. Briefing was completed in the fourth quarter of 2025. In the first quarter of 2026, the Denver District Court affirmed the CPUC’s decision on all counts appealed by PSCo.

Colorado Resource Plan — In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs.

In September 2025, the CPUC authorized a process for company-owned and PPA resources to seek up to 15% relief for tariff impacts to projects. Relief requests are due by Dec. 31, 2025 or 18 months prior to COD. The CPUC will ultimately review and approve/deny requests.

PSCo has filed all generation CPCNs associated with company-owned generation from the Colorado Resource Plan and expects to continue filing transmission CPCNs throughout 2026.

2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its Phase I electric resource plan with the CPUC. In November 2025, the CPUC approved a load forecast that reflects a 3% compound annual sales growth through 2031 and generation capacity need of approximately 5,400 MW.

PSCo filed a request for reconsideration of various aspects of the decision which were verbally approved in January 2026 (with a written decision related to those reconsideration requests expected in the first quarter of 2026). This decision is expected to initiate the Phase II competitive solicitation process with an RFP expected to be issued in the third quarter of 2026. This RFP will seek to acquire the balance of resource needs through 2031 (after consideration of any approved acquisitions from the Near-Term Procurement RFP).

Near-Term Procurement — In August 2025, PSCo filed a joint motion with state agencies to initiate a “fast-tracked” solution for tax-advantaged new generation resources. The CPUC approved the request in September 2025 with bids submitted in October 2025. The procurement seeks to accelerate development of up to 4,000 nameplate MW of clean energy resources, 200 accredited MW of firm, dispatchable resources, and up to 300 accredited MW of other dispatchable resources.

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The table below summarizes the recommended portfolio of resources filed in December 2025 (a decision is expected in February 2026):

(Nameplate MW)

Company Owned

PPA

Total

Wind

1,600 

1,100 

2,700 

Solar

— 

1,100 

1,100 

Natural gas combustion turbine

200 

— 

200 

Other storage

300 

600 

900 

Total

2,100 

2,800 

4,900 

In February 2026, the CPUC approved 3,200 MW of resources, which included PPAs and a 200 MW company-owned natural gas combustion turbine. Additionally, in March 2026 PSCo will file additional information related to 600-1,500 MW of company-owned wind, solar and storage resources that have been conditionally approved.

Grid Modernization Adjustment Clause (GMAC) — In December 2024, PSCo filed its 2025-2029 Distribution System Plan which included a request to implement the GMAC for recovery of distribution investments. The CPUC issued their decision in December 2025, as modified by an ARRR in February 2026, approving the inclusion of capacity expansion projects and certain other related costs. The CPUC indicated other categories of distribution costs may be considered for recovery within the GMAC in a future regulatory process, expected in late 2026 or 2027.

Colorado Senate Bill 23-291 — In May 2023, Colorado Senate Bill 23-291 was signed into law. The legislation included a number of topics including for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers.

In December 2024, the CPUC adopted final rules applicable to PSCo’s natural gas utility that would assign to the Company four percent of the change in the price per MMbtu of natural gas compared to the three-year average, subject to rolling 12-month cap based on a percentage of rate base, currently estimated at $7 million. PSCo made a filing in June 2025 to implement the mechanism and filed an unopposed settlement agreement in November 2025. In December 2025, a CPUC ALJ approved the settlement agreement, and PSCo implemented the gas fuel cost mechanism in January 2026.

In December 2024, the CPUC also adopted rules for electric utilities but did not adopt a specific PIM framework. PSCo made a filing in November 2025 to the CPUC to implement an electric fuel cost mechanism based on a current market-based index rather than a historical index as required for PSCo’s natural gas utility, subject to a cap currently estimated at $3 million. PSCo expects to implement the electric fuel cost mechanism in the second quarter of 2026.

Purchased Power and Transmission Service Providers

PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs.

Purchased Power — PSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of PSCo’s long-term purchased power is for wind, solar and storage resources. PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost.

Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.

Wholesale and Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to these hedging activities.

Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.

SPS

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

Additional Information

PUCT

Retail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations.

The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review.

NMPRC

Retail electric operations, retail rates and services and the construction of transmission or generation.

Reviews Integrated Resource Plans for meeting future energy needs.

FERC

Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.

SPP RTO and SPP Integrated and Wholesale Markets

SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets. SPS is authorized to make wholesale electric sales at market-based prices.

DOT

Pipeline safety compliance.

Recovery Mechanisms

Mechanism

Additional Information

Advanced Metering System Surcharge

Recovers costs incurred in deployment of the Advanced Metering System in Texas.

Consulting Fee Rider

Recovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT.

Distribution Cost Recovery Factor

Recovers distribution costs not included in rates in Texas, including recovery of deferred Texas System Resiliency Plan costs.

Electric Vehicle Rider

Recovers costs of the Transportation Electrification Plan in New Mexico.

Energy Efficiency Cost Recovery Factor

Recovers costs for energy efficiency programs in Texas.

Energy Efficiency Rider

Recovers costs for energy efficiency programs in New Mexico.

Fixed Fuel and Purchased Recovery Factor

Provides for the over- or under-recovery of energy expenses in Texas. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis if this condition is expected to continue.

Fuel and Purchased Power Cost Adjustment Clause

Adjusts monthly to recover actual fuel and purchased power costs in New Mexico.

Grid Modernization Rider

Recovers costs incurred in the implementation of Grid Modernization Components in New Mexico.

Generation Cost Recovery Rider

Recovers investments in a power generation facility outside of a base rate proceeding

Renewable Portfolio Standards

Recovers deferred costs for renewable energy programs in New Mexico.

Transmission Cost Recovery Factor

Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.

Wholesale Fuel and Purchased Energy Cost Adjustment

SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs.

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Pending and Recently Concluded Regulatory Proceedings

2025 New Mexico Electric Rate Case — In November 2025, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $175 million (16.7%). The request is based on a future test year period ending November 30, 2027, a ROE of 10.5%, an equity ratio of 56% and retail rate base of $3.9 billion.

The request reflects:

•Significant retail revenue growth.

•Continued capital investment primarily to support the clean energy transition and load growth.

•Planned roll-off of 100 MW of wholesale load in 2026.

SPS’ base rate request (millions of dollars):

Retail revenue growth

$

(204)

Increase in allocation of assets and costs to New Mexico retail, including impact of wholesale load roll-off

148 

Capital investment

133 

O&M expenses

36 

Depreciation rate changes and amortization

34 

Increase in requested ROE

28 

Total rate request

$

175 

The procedural schedule is as follows:

•Intervenor direct testimony: March 27, 2026

•Rebuttal testimony: April 17, 2026

•Public Evidentiary Hearing: May 26 - June 5, 2026

A NMPRC decision and implementation of final rates is anticipated in the second half of 2026.

SPS Resource Plan (IRP) — In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources.

In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited capacity by 2030. In July 2025, the portfolio selection report was publicly filed with the NMPRC with 3,121 MW of accredited capacity resources, including the following:

Generation Resource Nameplate Capacity (in MW)

Company Owned

PPAs

Total

Wind Resources

1,273 

— 

1,273 

Solar

695 

— 

695 

Storage

472 

640 

1,112 

Natural Gas

2,088 

— 

2,088 

Total

4,528 

640 

5,168 

SPS filed or expects to file Certificate of Convenience and Necessity filings for the specific assets with the PUCT and NMPRC in 2025 and 2026, with approvals expected in 2026 and 2027.

2025 Resource Acquisition – In October 2025, SPS issued a RFP to solicit 870 MW of accredited capacity (approximately 1,500 MW to 3,000 MW nameplate capacity) through 2032. Additional resources will be evaluated to meet the New Mexico Renewable Portfolio Standard compliance need. Bids were received in January 2026, and the portfolio is expected to be filed in the second half of 2026.

Excess Liability Insurance Deferral – In March 2025, SPS filed a request with the PUCT and in April 2025, SPS filed a request with the NMPRC for deferred accounting treatment for incremental excess liability insurance expense incurred as a result of the October 2024 policy renewal, estimated at approximately $30 million across the two jurisdictions. In October 2025, the NMPRC approved the request, resulting in a deferral of approximately $15 million of incremental excess liability insurance costs in 2025. In January 2026, SPS, PUCT Staff and other intervenors filed a black box settlement expected to result in annual deferrals of approximately $8 million in 2026 and 2027. A PUCT decision is expected in the first half of 2026.

Texas System Resiliency Plan — In December 2024, SPS filed its Texas SRP with the PUCT. Consistent with PUCT requirements, SPS’ proposed plan discusses resiliency-related risks and the five measures that have been designed to help SPS prevent, withstand, mitigate or more promptly recover from resiliency events, including wildfire. The proposed SRP covers 2025-2028 and includes a proposed $538 million of investment.

In April 2025, SPS filed a unanimous stipulation and settlement agreement. The settlement includes approximately $490 million of spend over the plan period, adjusted largely to reflect the removal of the operational flexibility measure for investment in the normal course of business. The settlement also includes the deferral of distribution-related costs, including depreciation expense and carrying costs at SPS’ weighted average cost of capital.

In July 2025, the PUCT approved the SRP, authorizing approximately $495 million of spend over the plan period, including reinstating previously removed distribution hardening projects.

Purchased Power Arrangements and Transmission Service Providers

SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.

Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.

Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.

Natural Gas

SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines, subject in certain cases to the regulation of the Railroad Commission of Texas. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA, DOT and PUCT for pipeline safety compliance.

Wholesale and Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.

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Other

Supply Chain

Xcel Energy’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. Xcel Energy 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, Trade Complaints and Federal Actions

Several trade cases related to anti-dumping and countervailing duty investigations are ongoing and we continue to monitor the potential impacts of these cases.

In 2025, several executive orders have been issued imposing new global and country-specific tariffs on many imports, which may impact our procurement and development activities. Additionally, executive orders and actions from government agencies may impact the permitting of wind and solar facilities and the retirement of coal facilities.

Xcel Energy continues to assess the impacts of these tariffs, executive orders, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief, if required, in its jurisdictions.

Continued and/or further policy actions or other restrictions, disruptions in imports from key suppliers, or any new trade complaint could impact viability, timelines and costs of various projects and PPAs.

Tax Law Changes

On July 4, 2025, the President signed into law Public Law No. 119-21 (the “OBBB”). The OBBB modifies certain clean energy tax provisions included in the Inflation Reduction Act. The provisions include:

•Eliminating production and investment tax credits for wind and solar facilities placed in service after 2027, for facilities that begin construction after July 4, 2026.

•The addition of foreign entity of concern rules that apply to projects commencing construction after 2025.

In August 2025, the U.S. Treasury issued further guidance related to the beginning of construction for clean energy projects. In February 2026, the U.S. Treasury and IRS released initial guidance regarding foreign entities of concern. The notice includes interim safe harbor guidance for the purposes of assessing material assistance from a prohibited foreign entity for wind, solar and storage tax credits. Further guidance is expected to be released throughout 2026 related to such rules.

Xcel Energy does not expect these provisions to have an impact on our 2026-2030 base capital plan, as steps have been taken to begin construction under the IRS’ safe harbor guidance.

Excess Liability Insurance Coverage

Xcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy’s employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States.

In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. In October 2025, Xcel Energy renewed its excess liability coverage for the same level with an annual premium of approximately $135 million. Xcel Energy has received approval to defer incremental costs in Colorado, Wisconsin and New Mexico and is awaiting approval of a settlement agreement allowing deferral of certain costs in Texas.

Critical Accounting Policies and Estimates

Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported.

Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.

Regulatory Accounting

Xcel Energy is subject to the accounting for Regulated Operations, which 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. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows.

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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. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.

Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.

As of Dec. 31, 2025 and 2024, Xcel Energy had regulatory assets of $3.5 billion and $3.4 billion, respectively and regulatory liabilities of $7.0 billion and $6.9 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income.

At Dec. 31, 2025, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets.

See Notes 4 and 12 to the consolidated financial statements for further information.

Income Tax Accruals

Judgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.

Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.

Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized.

We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings.

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

Employee Benefits

We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.

At Dec. 31, 2025, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which remains unchanged from the rate set at Dec. 31, 2024. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2025, which remains unchanged from the rate set in 2024. Xcel Energy’s pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan’s funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.

Xcel Energy set the discount rates used to value the pension obligations and postretirement health care obligations at 5.78% and 5.66% at Dec. 31, 2025, respectively. This represents a 10 basis point and 22 basis point decrease, respectively, from 2024. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy’s benefit plans in amount and duration.

The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.

If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2026 pension costs, net of the effects of regulation:

Pension Costs

(Millions of Dollars)

+1%

-1%

Rate of return

$

(12)

$

22 

Discount rate

(4)

— 

Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.

As of Dec. 31, 2025, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan.

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Funding contributions in 2025 were $125 million and will be $75 million in 2026. In future years contributions will remain relatively consistent. Investment returns were more than the assumed levels in 2025 and 2023, but were less than the assumed levels in 2024.

The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year.

As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2025).

Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $85 million in 2026, while the actual pension costs were $59 million in 2025 and $79 million in 2024.

Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2023 - 2026:

•$75 million in January 2026.

•$125 million in 2025.

•$100 million in 2024.

•$50 million in 2023.

Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $13 million in 2025 and $11 million during 2024 and 2023, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2026.

Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.

•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.

•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.

•Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.

•PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2025.

See Note 11 to the consolidated financial statements for further information.

Nuclear Decommissioning

Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.

A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.6 billion in 2025 and $2.5 billion in 2024.

NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed and was approved by the MPUC in May 2025.

The following assumptions have a significant effect on the estimated nuclear obligation:

Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit’s operating license with the NRC.

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 Prairie Island Unit 1 and 2034 for Prairie Island Unit 2. During 2025, the Commission approved extended lives for Prairie Island Unit 1 and Unit 2 and Monticello (2053, 2054, and 2050, respectively) in the Upper Midwest Resource Plan. A request to update authorized retirement dates and related decommissioning estimates to incorporate the extended lives are pending with the Commission. These will be incorporated in decommissioning estimates once additional approvals have been received.

The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101.

Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly.

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Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used escalation rates of 3.30% and 4.50%, for non-labor and labor expenses respectively, in calculating the ARO for nuclear decommissioning of its nuclear facilities.

Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.

If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.

Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.

However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.

NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time.

This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2025.

See Note 12 to the consolidated financial statements for further information.

Loss Contingencies – Wildfires

The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigation, legal proceedings, mediations and settlements are considered. See Note 12 accompanying the consolidated financial statements for additional information.

Derivatives, Risk Management and Market Risk

We are 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.

Xcel Energy 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 we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us 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 — Xcel Energy 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. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.

Fair value of net commodity trading contracts as of Dec. 31, 2025:

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)

$

(10)

$

(15)

$

(3)

$

(1)

$

(29)

NSP-Minnesota (b)

1 

(2)

— 

(4)

(5)

PSCo (a)

(1)

— 

— 

— 

(1)

$

(10)

$

(17)

$

(3)

$

(5)

$

(35)

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)

$

— 

$

10 

$

10 

$

— 

$

20 

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

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

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

(Millions of Dollars)

2025

2024

Fair value of commodity trading net contracts outstanding at Jan. 1

$

(2)

$

1 

Contracts realized or settled during the period

(1)

— 

Commodity trading contract additions and changes during the period

(12)

(3)

Fair value of commodity trading net contracts outstanding at Dec. 31

$

(15)

$

(2)

A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2025 and Dec. 31, 2024.

The utility subsidiaries’ 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

2025

$

— 

$

— 

$

1 

$

— 

2024

— 

— 

1 

— 

Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our 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 Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $17 million and $7 million in 2025 and 2024, respectively.

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

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 our credit risk.

Xcel Energy’s subsidiaries are subject to credit risk from contracts with generating equipment manufacturers and other suppliers that require deposits or milestone payments. In the event of non-performance by these counterparties, the Xcel Energy subsidiaries could experience credit losses, increased costs or project delays. Xcel Energy frequently seeks to mitigate this risk by requiring parent guarantees, letters of credit or other types of credit support.

Xcel Energy is also subject to credit risk 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.

At Dec. 31, 2025, a 10% increase or decrease in commodity prices would have resulted in an increase or decrease in credit exposure of $27 million. At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $25 million.

Fair Value Measurements

Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.

Liquidity and Capital Resources

Cash Flows

Operating Cash Flows

(Millions of Dollars)

Twelve Months Ended Dec. 31

Cash provided by operating activities — 2024

$

4,641 

Components of change — 2025 vs. 2024

Higher net income

82 

Non-cash transactions

121 

Changes in deferred taxes

189 

Changes in working capital

(304)

Changes in net regulatory and other assets and liabilities

(646)

Cash provided by operating activities — 2025

$

4,083 

Net cash provided by operating activities decreased by $558 million for 2025 as compared to 2024. The decrease was largely due to the payment of the Marshall Wildfire settlement and timing of regulatory recovery, including deferred fuel costs.

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Investing Cash Flows

(Millions of Dollars)

Twelve Months Ended Dec. 31

Cash used in investing activities — 2024

$

(7,428)

Components of change — 2025 vs. 2024

Increased capital expenditures

(3,544)

Other investing activities

3 

Cash used in investing activities — 2025

$

(10,969)

Net cash used in investing activities increased by $3,541 million for 2025 as compared to 2024. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.

Financing Cash Flows

(Millions of Dollars)

Twelve Months Ended Dec. 31

Cash provided by financing activities —2024

$

2,837 

Components of change — 2025 vs. 2024

Higher long-term debt issuances, net of repayments

1,059 

Higher net short-term debt proceeds

945 

Higher proceeds from issuance of common stock

2,232 

Other financing activities

(92)

Cash provided by financing activities — 2025

$

6,981 

Net cash provided by financing activities increased by $4,144 million for 2025 as compared to 2024. The increase was largely related to additional debt and common stock issuances to fund capital investment.

See Note 5 to the consolidated financial statements for further information.

Capital Requirements

Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy’s financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation.

Material Cash Requirements and Other Commitments

Payments Due by Period (as of Dec. 31, 2025)

(Millions of Dollars)

Total

Less than 1 Year

1 to 3 Years

3 to 5 Years

After 5 Years

Long-term debt, principal and interest payments

$

57,743 

$

1,937 

$

4,766 

$

3,793 

$

47,247 

Finance lease obligations

2,183 

112 

225 

232 

1,614 

Operating leases obligations (a)

1,259 

152 

250 

226 

631 

Unconditional purchase obligations (b)

4,264 

1,264 

1,097 

520 

1,383 

Short-term debt

1,550 

1,550 

— 

— 

— 

Other

587 

574 

13 

— 

— 

Total contractual cash obligations

$

67,586 

$

5,589 

$

6,351 

$

4,771 

$

50,875 

(a)Included in operating lease obligations are $121 million, $170 million, $156 million and $185 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that are accounted for as operating leases.

(b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms.

Capital Expenditures — Base capital expenditures for Xcel Energy for 2026 through 2030:

Actual

Base Capital Forecast (Millions of Dollars)

By Regulated Utility

2025

2026

2027

2028

2029

2030

2026 - 2030 Total

NSP-Minnesota

$

3,380 

$

3,740 

$

4,870 

$

4,210 

$

3,660 

$

3,650 

$

20,130 

SPS

1,610 

3,050 

5,120 

5,350 

3,240 

2,270 

19,030 

PSCo

5,440 

5,980 

3,940 

2,960 

1,760 

2,960 

17,600 

NSP-Wisconsin

710 

910 

1,210 

760 

570 

580 

4,030 

Other (a)

470 

110 

(10)

(630)

(210)

(50)

(790)

Total base capital expenditures

$

11,610 

$

13,790 

$

15,130 

$

12,650 

$

9,020 

$

9,410 

$

60,000 

(a)Other category includes intercompany transfers for equipment with long lead times.

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Actual

Base Capital Forecast (Millions of Dollars)

By Function

2025

2026

2027

2028

2029

2030

2026 - 2030 Total

Electric transmission

$

2,250 

$

3,060 

$

2,930 

$

2,890 

$

3,190 

$

3,370 

$

15,440 

Renewables

3,190 

3,560 

4,620 

3,380 

1,150 

1,210 

13,920 

Electric distribution

2,690 

2,920 

3,250 

2,930 

1,680 

2,930 

13,710 

Electric generation

1,250 

2,220 

2,420 

2,500 

1,810 

590 

9,540 

Natural gas

740 

860 

830 

700 

650 

680 

3,720 

Other

1,490 

1,170 

1,080 

250 

540 

630 

3,670 

Total base capital expenditures

$

11,610 

$

13,790 

$

15,130 

$

12,650 

$

9,020 

$

9,410 

$

60,000 

The plan does not include any potential incremental generation from the current Colorado Near-Term Procurement and Resource Plan, additional future generation RFPs across jurisdictions to fund growth, or additional transmission investments that may come from future planning processes including MISO and SPP. Xcel Energy expects to fund additional capital investment with approximately 40% equity and 60% debt.

Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.

Financing for Capital Expenditures through 2030 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes.

Current estimated financing plans of Xcel Energy for 2026 through 2030 (includes the impact of tax credit transferability):

(Millions of Dollars)

Funding Capital Expenditures

Cash from operations (a)

$

30,180 

New debt (b)

22,820 

Equity issuances (c)

7,000 

Base capital expenditures 2026 - 2030

$

60,000 

Maturing debt

$

3,580 

(a)Net of dividends and pension funding.

(b)Reflects a combination of short and long-term debt; net of refinancing.

(c)Amount could include other financing instruments that receive equity credit from the credit rating agencies.

Off-Balance Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2026, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.0%.

Xcel Energy’s dividend policy balances the following:

•Projected cash generation.

•Projected capital investment.

•A reasonable rate of return on shareholder investment.

•The impact on Xcel Energy’s capital structure and credit ratings.

In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.

See Note 5 to the consolidated financial statements for further information.

Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds.

Funded status and pension assumptions:

(Millions of Dollars)

Dec. 31, 2025

Dec. 31, 2024

Fair value of pension assets

$

2,690 

$

2,504 

Projected pension obligation (a)

2,820 

2,752 

Funded status

$

(130)

$

(248)

(a)Excludes non-qualified plan of $13 million at both Dec. 31, 2025 and 2024.

Pension Assumptions

2025

2024

Discount rate for year-end valuation

5.78 

%

5.88 

%

Expected long-term rate of return

7.13 

7.13 

Capital Sources

Short-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.

Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts.

Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:

•$2 billion for Xcel Energy Inc.

•$1.2 billion for PSCo.

•$800 million for NSP-Minnesota.

•$600 million for SPS.

•$150 million for NSP-Wisconsin.

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Table of Contents     

See Note 5 to the consolidated financial statements for further information.

Credit Facility Agreements — As of Feb. 23, 2026, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

(Millions of Dollars)

Facility (a)

Drawn (b)

Available

Cash

Liquidity

Xcel Energy Inc.

$

2,000 

$

790 

$

1,210 

$

21 

$

1,231 

PSCo

1,200 

308 

892 

9 

901 

NSP-Minnesota

800 

329 

471 

3 

474 

SPS

600 

213 

387 

11 

398 

NSP-Wisconsin

150 

— 

150 

2 

152 

Total

$

4,750 

$

1,640 

$

3,110 

$

46 

$

3,156 

Term Loan (c)

1,500 

750 

750 

— 

750 

(a)Credit facilities expire in December 2029.

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

(c)Xcel Energy Inc.’s $1.5 billion term loan (entered into in January 2026) matures in January 2027.

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval.

Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2025 and 2024, Xcel Energy had approximately 624 million shares and 574 million shares of common stock outstanding, respectively.

Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval.

Planned Financing Activity — Xcel Energy’s 2026 financing plans reflect the following:

Issuer

Security

Amount (Millions of Dollars)

Xcel Energy Inc.

Senior Unsecured Notes

$

1,000 

PSCo

First Mortgage Bonds

2,400 

NSP-Minnesota

First Mortgage Bonds

1,000 

SPS

First Mortgage Bonds

1,000 

NSP-Wisconsin

First Mortgage Bonds

250

In addition, Xcel Energy plans to issue incremental equity throughout 2026 through its ATM program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.

In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility.

See Note 5 to the consolidated financial statements for further information.

Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2026 Earnings Guidance — Xcel Energy’s 2026 ongoing earnings guidance is a range of $4.04 to $4.16 per share. (a)

Key assumptions as compared with 2025 actual levels unless noted:

•Constructive outcomes in all pending rate case and regulatory proceedings.

•Normal weather patterns for the year.

•Weather-normalized retail electric sales are projected to increase ~3%.

•Weather-normalized retail firm natural gas sales are projected to increase ~1%.

•Capital rider revenue is projected to increase $535 million to $545 million.

•O&M expenses are projected to increase ~3%.

•Depreciation expense is projected to increase approximately $350 million to $360 million.

•Property taxes are projected to increase $30 million to $40 million.

•Interest expense (net of AFUDC - debt) is projected to increase $300 million to $310 million, net of interest income.

•AFUDC - equity is projected to increase $140 million to $150 million.

(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.

Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:

•     Deliver long-term annual EPS growth of 6% to 8+% based off of $3.80 per share.

•    Deliver annual dividend increases of 4% to 6%.

•     Target a dividend payout ratio of 45% to 55%.

•     Maintain senior secured debt credit ratings in the A range.