What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-25 compared with 2025-02-27 · 326 added, 318 removed, 753 unchanged (46% of the section changed)

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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 is adjusted from measures calculated and presented in accordance with GAAP.

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.

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These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

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 stockholder’s equity.

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.

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

Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc.

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 of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc.

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.

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GAAP net income $ 2,018 $ 1,936

Loss on Comanche Unit 3 litigation — 35

Workforce reduction expenses — 72

Sherco Unit 3 2011 outage refunds — 47

Marshall Wildfire litigation (a)

tax effect of adjustments (77) (13)

Ongoing earnings (a)

Ongoing earnings (b)

$ 2,239 $ 1,969

(a) Amounts may not add due to rounding.

(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.

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NSP-Minnesota $ 1.41 $ 0.06 $ 1.47

1.26 0.08 1.33

PSCo 1.39 — 1.39

SPS 0.70 — 0.70

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Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine.

In 2024, following contested case procedures, Xcel Energy recognized a customer refund of $47 million for replacement power incurred during the outage.

Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a non-recurring $34 million charge as a result of a jury verdict in Denver County District Court awarding CORE Electric Cooperative lost power damages and other costs.

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

Xcel Energy initiated a Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired.

Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program.

Workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023.

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.

Results of Operations

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GAAP diluted EPS (a)

Loss on Comanche Unit 3 litigation — 0.05

Workforce reduction expenses — 0.09

$ 3.42 $ 3.44

Sherco Unit 3 2011 outage refunds — 0.06

Marshall Wildfire settlement 0.38 —

Ongoing diluted EPS (a)

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2025 Comparison with 2024

Xcel Energy — GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023.

The change in EPS was driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses.

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 and natural gas infrastructure investments, partially offset by increased depreciation and interest charges.

PSCo — GAAP earnings increased $0.13 per share and ongoing earnings increased $0.06 per share for 2024.

Higher ongoing earnings primarily reflects higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation, O&M and interest charges.

SPS — GAAP earnings were flat and ongoing earnings decreased $0.01 per share for 2024.

Ongoing earnings were impacted by increased depreciation, O&M and interest charges, largely offset by regulatory rate outcomes and sales growth.

NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 per share for 2024.

The decrease in ongoing earnings was primarily a result of higher depreciation.

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 decline in earnings for 2024 is largely due to higher debt levels and increased interest rates, partially offset by a gain on debt repurchases.

The change in earnings was due to gains on debt repurchases, partially offset by higher interest rates and debt levels.

Changes in Diluted EPS

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Components of change — 2025 vs.

Electric regulatory rate outcomes and riders 0.73

Higher other income, net 0.16

Natural gas regulatory rate outcomes and riders 0.14

Workforce reduction expenses 0.09

Loss on Comanche Unit 3 litigation 0.05

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)

Interest charges, net of AFUDC - debt (0.24)

Higher O&M expenses (0.25)

Sherco Unit 3 2011 outage refunds (0.06)

Higher electric fuel and purchased power (a)

Common equity financing (0.18)

Higher costs of natural gas sold and transported (a)

Other, net (0.13)

GAAP diluted EPS — 2025 $ 3.42

Sherco Unit 3 2011 outage refunds 0.06

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:

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As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance.

However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.

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.

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

• NSP-Minnesota — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers.

The decline in C&I sales was due to lower use per customer, particularly in the manufacturing sector.

• PSCo — Residential sales increased due to a 1.4% increase in customers, partially offset by a 0.7% decrease in use per customer.

The decline in C&I sales was attributable to decreased use per customer, particularly in the wholesale trade and mining.

• SPS — Residential sales declined due to a 2.2% decrease in use per customer partially offset by a 0.7% increase in customers.

C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining.

• NSP-Wisconsin — Residential sales declined due to a 2.7% decrease in use per customer, offset by a 1.0% increase in customers.

The C&I sales decline was associated with lower use per customer, experienced particularly in the professional services and manufacturing sectors.

• 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)

• Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases.

Partially offsetting these were increased residential and C&I customers in all jurisdictions.

• 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 changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality.

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.

(Millions of Dollars) 2025 vs.

Recovery of lower cost of electric fuel and purchase power (479)

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

Wholesale generation revenues (96)

Regulatory rate outcomes (MN, ND) 116

Sales and demand

Transmission revenues 79

Sherco Unit 3 2011 outage refunds 47

Regulatory rate outcomes (MN, CO, TX, and NM) 372

Non-fuel riders 169

Estimated impact of weather (39)

Conservation and demand side management (offset in expense) (38)

Estimated impact of weather (net of sales true-up) 24

Other, net 115

Total decrease $ (299)

Total increase $ 1,013

Natural Gas Revenues

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(Millions of Dollars) 2025 vs.

Recovery of lower cost of natural gas $ (496)

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)

Regulatory rate outcomes (MN, WI, CO, and ND) 91

Infrastructure and integrity riders 8

Other, net 18

Total decrease $ (415)

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality.

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 decreased $490 million in 2024.

The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices, partially offset by increased volumes.

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.

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As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.

Natural gas sold and transported decreased $505 million in 2024.

The decrease is primarily due to lower commodity prices and volumes.

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 $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention.

The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially offset by lower labor and benefit costs and lower bad debt expenses.

Depreciation and Amortization — Depreciation and amortization increased $296 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions.

Other Income — Other income increased $121 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gain on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation.

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 debt levels to fund capital investments and higher interest rates.

AFUDC, Equity and Debt — AFUDC increased $99 million in 2024.

This increase was largely due to increased investment in renewable and transmission projects.

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.

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Xcel Energy Inc.

taxes and other results (a)

other results (a)

Total Xcel Energy Inc.

and other costs $ (185) $ (173)

and other $ (136) $ (185)

(Diluted Earnings (Loss) Per Share) 2025 2024

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Xcel Energy Inc.

taxes and other results (a)

other results (a)

Total Xcel Energy Inc.

and other costs $ (0.23) $ (0.33)

(a) Amounts include gain from open market debt repurchases in 2024.

(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.

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Public Utility Regulation

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate.

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.

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CIP Rider Recovers costs of conservation and DSM programs.

Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP.

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.

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Gas Utility Infrastructure Cost Rider Recovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.

Infrastructure Rider Recovers costs for investments in generation in South Dakota.

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 to support research and development of emerging renewable energy projects and technologies in Minnesota.

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.

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Sales True-up Mitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers.

State Energy Policy Electric Rider Recovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.

Transmission Cost Recovery Rider Recovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization.

Pending and Recently Concluded Regulatory Proceedings

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

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

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

• ROE of 9.6%.

• Equity ratio of 52.5%.

• Rate base of $1.25 billion.

• No change to Commission approved decoupling.

In October 2024, an ALJ recommended the MPUC approve the rate case settlement.

In February 2025, the MPUC verbally approved the settlement agreement.

NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.

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

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

Rates were implemented on Jan.

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.

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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.

The opinion is currently pending further action from the MPUC.

2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026.

NSP-Minnesota also requested interim rates of $224 million for 2025.

In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025.

A decision is expected in 2026.

2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021.

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.

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.

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.

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

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Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.

Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.

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.

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NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.

In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054.

NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.

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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The PSCW has a biennial base rate filing requirement.

By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.

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.

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

Wisconsin Energy Efficiency Program The primary energy efficiency program is funded by the utilities, but operated by independent contractors subject to oversight by the PSCW and utilities.

NSP-Wisconsin recovers these costs 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

Michigan Electric Rate Case — In July 2024, NSP-Wisconsin filed a Michigan electric rate case with the MPSC.

In December 2024, the MPSC approved NSP-Wisconsin’s settlement agreement.

The settlement order includes an electric rate increase of $1.75 million in 2025 and a step increase of $0.55 million in 2026, based on a ROE of 9.8% and an equity ratio of 50%.

Wisconsin 2025 Stay-Out Proposal — In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW.

In December 2024, the PSCW approved NSP-Wisconsin’s filing, which offsets $27 million in electric deficiencies and $3 million in natural gas deficiencies by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two natural gas capital projects.

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.

A PSCW decision is expected in the third quarter of 2025.

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)

NSP-Wisconsin’s filed two-year rate request

PSCW decision:

Capital investments

ROE adjustment

Nuclear decommissioning accrual update (a)

Excess liability insurance deferral recovery 4 1

Total revenue change

(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%.

Pending and Recently Concluded Regulatory Proceedings

Resource Acquisition — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC.

In October 2024, NSP-Minnesota filed a settlement with several parties reaching agreement on the resource plan, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition.

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

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

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

• Multiple PPAs to proceed to the negotiation stage.

• The addition of 3,200 MW of wind, 400 MW of solar and 600 MW of stand-alone storage to be added through 2030 based on an RFP process (a portion of which is expected to be fulfilled with the resources acquired as part of the 2024 RFPs).

Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line.

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

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

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

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

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The RFP closed in December 2023.

NSP-Minnesota expects to file for approval of recommended projects in summer 2025.

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.

Bids are currently under evaluation;

NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025 and plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second half of 2025.

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

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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.

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

Electric Commodity Adjustment Recovers fuel and purchased energy costs.

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 generation are returned to 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.

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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.

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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 retail revenues, respectively.

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

Colorado Natural Gas Rate Case — In January 2024, PSCo, filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million (9.5%).

The request was based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year and a $4.2 billion year-end rate base.

In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including the following key decisions:

• Use of a historic 2023 test year, with a 13-month average rate base.

• Weighted-average cost of capital of 7.0%, based on an ROE range of 9.2%-9.5% and an equity ratio range of 52%-55%.

• Acceleration of $15 million per year of depreciation expense (incremental to PSCo’s original rate request), to be held in an external trust for future decommissioning costs.

• Modifications to recoverability of certain operating expenses.

• Denial of PSCo’s decoupling proposal.

PSCo placed new rates into effect in November, as modified on ARRR in February 2025, with an annual revenue increase of approximately $125 million, inclusive of $15 million of accelerated depreciation.

The UCA filed a second ARRR in February 2025, which remains pending.

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)

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)

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 December 2023, the CPUC approved a framework for two PIMs associated with the generation projects in the portfolio — a PIM related to capital construction costs and another related to ongoing levelized energy costs with details to be further defined via subsequent proceedings throughout 2024.

In September 2024, PSCo filed a proposal for implementation of the PIMs.

Intervenor testimony is due Feb.

27, 2025, with a final decision expected in summer 2025.

In September 2024, PSCo filed a proposed framework for CPUC review of pricing adjustments for both company owned and PPA resources to enable delivery of the approved portfolio in light of supply chain and geopolitical developments.

In January 2025, the CPUC issued a decision granting limited potential pricing relief, subject to evaluation in future CPCN proceedings for company owned projects.

PSCo filed or expects to file generation and transmission CPCNs throughout 2024 and 2025.

2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its electric resource plan with the CPUC.

The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources.

• The plan reflects a base sales forecast with 7% compound annual sales growth through 2031.

• The plan also presents a low sales forecast with a 3% compound annual sales growth through 2031.

• The resource plan includes forecasted need of 5-14 GW of new generation capacity through 2031, including renewables and firm dispatchable resources to meet the two different scenarios.

The acquisitions of generation resources will be determined through a competitive solicitation after the CPUC determines the portfolio.

The table below summarizes two of the proposed portfolios based on the different sales scenarios:

(MW) Base Plan Low Load

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.

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

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Natural gas combustion turbine 200 — 200

Storage (long duration) 1,600 —

Other storage 300 600 900

Total 2,100 2,800 4,900

The procedural schedule is as follows:

• Answer testimony:

April 18, 2025

• Rebuttal testimony:

• Settlement deadline:

June 10-20, 2025

• Statements of position:

July 14, 2025

A CPUC decision on the resource plan is expected by the fall of 2025 (Phase I) with the competitive solicitation for resource additions expected in early 2026.

Wildfire Mitigation Plan — In June 2024, PSCo filed an updated WMP and request for recovery of costs covering the years 2025 to 2027 with the CPUC.

The estimated total cost for this plan is approximately $1.9 billion.

A CPUC decision is expected in the third quarter of 2025.

The WMP integrates industry experience;

incorporates evolving risk assessment methodologies;

adds new technology;

and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner under four core programs that include the following:

• Situational awareness — Meteorology, area risk mapping and modeling, artificial intelligence cameras and continuous monitoring.

• Operational mitigations – Enhanced powerline safety settings and PSPS.

• System resiliency — Asset assessment and remediations, pole replacements, line rebuilds, targeted undergrounding and vegetation management.

• Customer support — Coordination and real-time data sharing with customers and other stakeholders and PSPS resiliency rebates.

In February 2025, six of the nine intervenors filed answer testimony in the proceeding.

Intervenors provided a range of recommendations related to both the scope of proposed work and the cost recovery proposal.

The remaining procedural schedule is as follows:

• Rebuttal testimony:

March 21, 2025

• Settlement deadline:

April 11, 2025

May 5-15, 2025

• Decision deadline:

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 bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).

In November 2023, the CPUC approved PSCo’s natural gas price risk plan to manage customer bill volatility from commodity price changes, establishing upper and lower limits for changes in the GCA rate.

As a result, costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit deferred as a reserve against future cost increases.

The legislation also calls 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.

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.

The rules require PSCo to make a filing to implement the mechanism within sixty days of becoming effective, expected later in 2025.

In December 2024, the CPUC also adopted rules for electric utilities but did not adopt a specific PIM framework, which will be further considered through additional proceedings in 2025.

Colorado Senate Bill 24-218 — In May 2024, Colorado Senate Bill 24-218 was signed into law.

The bill includes a suite of policy changes to accelerate investment in electric distribution, including a framework to develop distribution planning and performance requirements and the opportunity for current cost recovery through a rider for distribution investments.

In July 2024 and December 2024, the CPUC approved PSCo’s request to collect $17 million and $48 million through a rider, over the remainder of 2024 and 2025, respectively, subject to true-up, associated with forecasted capital investments covered by the new legislation.

Excess Liability Insurance Deferral — In August 2024, PSCo filed a request with the CPUC to establish a tracker to defer differences in excess liability insurance premiums after the October 2024 policy renewal (reflecting significantly rising premiums of approximately $40 million, largely associated with wildfire risks throughout the United States) and amounts currently recovered.

In January 2025, the CPUC approved a one-year deferral aligned with the current insurance policy year.

Cost recovery for incremental insurance premiums will be reviewed in a future rate case.

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

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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.

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.

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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.

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Pending and Recently Concluded Regulatory Proceedings

2023 Texas Electric Rate Case — In 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $158 million (14%).

Interim rates went into effect on Feb.

In April 2024, the PUCT approved a black box settlement between SPS and intervening parties, which reflect the following terms:

• A base rate increase of $65 million effective back to July 13, 2023.

• A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction and in other proceedings filed before the PUCT where a stated WACC is required.

• The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028.

• Establishment of a rate rider of approximately $18 million to be recovered over a three-year period for various deferred expenses.

In July 2024, SPS filed to surcharge the final under-recovered amount of $37 million.

This will be largely offset by previously deferred costs.

In February 2025, the PUCT approved the surcharge.

2022 All-Source RFP — In July 2023, SPS filed for approval of a CPCN for a recommended generation portfolio, which includes 418 MW of self-build solar projects and a 36 MW battery.

The NMPRC approved the projects in May 2024.

In July 2024, the PUCT approved the solar projects and denied the battery project.

The PUCT’s approval included minimum production and PTC guarantees.

New Mexico 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.

SPS’ projected resource needs ranging from approximately 5,300 MW to 10,200 MW by 2030.

In February 2024, the NMPRC accepted the IRP.

In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited generation capacity by 2030.

The total capacity to be added to the system is expected to align with the range identified in the SPS IRP, depending on the types of resources proposed in the RFP and their accredited capacity factors.

The RFP portfolio selection is expected in May 2025.

SPS is expected to file for a CON for the recommended portfolio in the summer of 2025.

The PUCT and NMPRC are expected to rule on the portfolio in 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 SRP includes the following measures:

• Distribution overhead hardening — Replacing and reinforcing key components of the distribution overhead system.

• Distribution system protection modernization — Installing enhanced reclosers, communications equipment and replacing substation relay panels and breakers.

• Communication modernization — Building out a private LTE network, installing fiber optic cable and adding remote terminal units.

• Operational flexibility — Procuring mobile substation equipment and installing additional switching devices.

• Wildfire mitigation — Weather stations, modeling, deploying artificial intelligence and vegetation management.

The plan covers 2025-2028 and includes the following total spend:

(Millions of Dollars) Capital O&M Total

Distribution overhead hardening $ 253 $ — $ 253

Distribution system protection modernization 92 — 92

Communication modernization 112 — 112

Operational flexibility 44 — 44

Wildfire mitigation 20 17 37

Total $ 521 $ 17 $ 538

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 testimony:

February 28, 2025

• Staff testimony:

• Intervenor direct testimony:

March 27, 2026

• Rebuttal testimony:

March 17, 2025

March 25-26, 2025

A PUCT decision is expected in the summer of 2025.

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.

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

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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 and Trade Complaints

In May 2024, the U.S.

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

In October 2024, the U.S.

Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact Xcel Energy projects.

In November 2024, the U.S.

Department of Commerce concluded that dumping had occurred and the impact to Xcel Energy is still being evaluated.

In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures.

The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications.

In January of 2025, the U.S.

International Trade Commission made an affirmative determination in the preliminary phase of the anti-dumping and countervailing duty investigations concerning Active Anode Material, a component of lithium-ion batteries, from China.

This case will be reviewed by the U.S.

Department of Commerce and the International Trade Commission over the course of 2025.

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

Xcel Energy continues to assess the impacts of these tariffs, trade complaints and federal policies on its business, including company owned projects and PPAs.

Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions.

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

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

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The annual premium for this excess liability insurance is approximately $130 million.

Xcel Energy received an approved deferral at PSCo, filed a deferral request at NSP-Wisconsin and will continue to seek to recover these increased costs through various regulatory proceedings, including planned deferral requests or rate filings in several states.

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

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Pension assumptions are continually reviewed.

31, 2024, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which is a 20 basis point increase from the rate set 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.

The rate of return used to measure postretirement health care costs is 6.25% at Dec.

31, 2024, which is a 125 basis point increase from the rate set in 2023.

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 both the pension obligations and postretirement health care obligations at 5.88% at Dec.

This represents a 39 basis point and 34 basis point increase, respectively, from 2023.

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.

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Funding contributions in 2025 were $125 million and will be $75 million in 2026.

In future years contributions will decrease slightly but then remain relatively consistent.

Investment returns were less than the assumed levels in 2024 and 2022, but were more than the assumed levels in 2023.

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.

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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 $60 million in 2025 and $69 million in 2026, while the actual pension costs were $79 million in 2024 and $74 in 2023.

The expected decrease in 2025 is primarily due to the absence of a pension settlement.

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:

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Therefore, additional contributions could be required in the future.

Xcel Energy contributed $11 million, $11 million and $13 million during 2024, 2023 and 2022, respectively, to the postretirement health care plans.

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.

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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.

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 (i.e., 2050 for Monticello and 2033 and 2034 for Prairie Island Units 1 and 2, respectively).

In December 2024, the operating license for Xcel Energy’s Monticello Nuclear Generating Plant in Monticello, MN was renewed.

The approval allows the plant to operate an additional 20 years, through 2050.

31, 2024, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2033, 2034 and 2040.

In February 2025, the MPUC approved the planned life extension through 2050 as part of the Upper Midwest Resource Plan.

These will be incorporated in decommissioning estimates in 2025 once additional approvals have been received.

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.

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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 an escalation rate of 3.8% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors.

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.

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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 investigations and legal proceedings are considered.

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.

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(1) — — — (1)

$ (10) $ (17) $ (3) $ (5) $ (35)

Options Maturity

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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, 2024 and $4 million at Dec.

31, 2025 and Dec.

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.

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2025 $ — $ — $ 1 $ —

Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States.

In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law.

As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received.

Interest Rate Risk — Xcel Energy is subject to interest rate risk.

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Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

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 a decrease in credit exposure of $25 million.

31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $24 million.

Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.

Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

Distress in the financial markets could increase 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.

31, 2025, a 10% increase or decrease in commodity prices would have resulted in an increase or decrease in credit exposure of $27 million.

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

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Net cash provided by operating activities decreased by $558 million for 2025 as compared to 2024.

The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers.

The decrease was largely due to the payment of the Marshall Wildfire settlement and timing of regulatory recovery, including deferred fuel costs.

Investing Cash Flows

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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

Higher dividends paid to shareholders (83)

Other financing activities (92)

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1,259 152 250 226 631

Unconditional purchase obligations (b) (c)

3,755 1,432 1,207 432 684

Other long-term obligations, including current portion (d)

Unconditional purchase obligations (b)

4,264 1,264 1,097 520 1,383

Other short-term obligations 632 632 — — —

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

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Effects of price changes are mitigated through cost of energy adjustment mechanisms.

(c) Amounts exclude approximately $1 billion of incremental payments related to SPS’ renegotiation and extension of a non-lease PPA that received PUCT approval in February 2025.

The extension to 2040 will result in annual payments of approximately $65 million to $80 million commencing in 2025.

(d) Primarily consists of contracts for information technology services.

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

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By Regulated Utility 2025 2026 2027 2028 2029 2030 2026 - 2030 Total

PSCo $ 3,180 $ 5,820 $ 5,190 $ 3,940 $ 3,780 $ 3,550 $ 22,280

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

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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 safe harbor wind turbines.

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

Actual Base Capital Forecast (Millions of Dollars)

By Function 2025 2026 2027 2028 2029 2030 2026 - 2030 Total

Electric distribution $ 2,220 $ 2,570 $ 3,000 $ 3,400 $ 3,320 $ 3,540 $ 15,830

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

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Total base capital expenditures $ 11,610 $ 13,790 $ 15,130 $ 12,650 $ 9,020 $ 9,410 $ 60,000

The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through an RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of $10 billion or greater.

Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt.

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.

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Cash from operations (a)

Equity through the DRIP and benefit program 500

Other equity 4,000

Equity issuances (c)

Base capital expenditures 2026 - 2030 $ 60,000

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net of refinancing.

Off-Balance Sheet Arrangements

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Funded status $ (130) $ (248)

(a) Excludes non-qualified plan of $13 million and $12 million at Dec.

31, 2024 and 2023, respectively.

(a) Excludes non-qualified plan of $13 million at both Dec.

31, 2025 and 2024.

Pension Assumptions 2025 2024

Discount rate 5.88 % 5.49 %

Discount rate for year-end valuation 5.78 % 5.88 %

Expected long-term rate of return 7.13 7.13

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• $2 billion for Xcel Energy Inc.

• $700 million for PSCo.

• $1.2 billion for PSCo.

• $800 million for NSP-Minnesota.

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Total $ 4,750 $ 1,640 $ 3,110 $ 46 $ 3,156

(a) Credit facilities expire in September 2027.

Term Loan (c)

1,500 750 750 — 750

(a) Credit facilities expire in December 2029.

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

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.

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Debt issuance at our utility subsidiaries are subject to commission approval.

Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its ATM program, forward equity agreements 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.

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

Issuer Security Amount (Millions of Dollars) Expected Tenor Anticipated Timing

Issuer Security Amount (Millions of Dollars)

Xcel Energy Inc.

Senior Unsecured Notes $ 1,000 10 Year First Quarter

PSCo First Mortgage Bonds 2,000 10 Year &

30 Year Second & Third Quarter

NSP-Minnesota First Mortgage Bonds 1,100 10 Year &

30 Year First & Third Quarter

SPS First Mortgage Bonds 450 30 Year Second Quarter

NSP-Wisconsin First Mortgage Bonds 250 30 Year Second Quarter

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.

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Key assumptions as compared with 2025 actual levels unless noted:

• Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.

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

• Normal weather patterns for the year.

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

• Capital rider revenue is projected to increase $260 million to $270 million (net of PTCs).

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

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

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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 $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).

• 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%.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis