What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2025-02-27 compared with 2024-02-21 · 387 added, 362 removed, 684 unchanged (52% of the section changed)

17 unchanged sentences

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 earnings per share, we may adjust the related GAAP amounts for certain items that are non-recurring in nature.

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.

5 unchanged sentences

Workforce reduction expenses — 72

Sherco Unit 3 2011 outage refunds 47 —

tax effect of adjustments (13) (27)

Ongoing earnings $ 1,851 $ 1,736

Ongoing earnings (a)

$ 1,969 $ 1,851

(a) Amounts may not add due to rounding.

Twelve Months Ended Dec.

2 unchanged sentences

NSP-Minnesota $ 1.41 $ 0.06 $ 1.47

1.26 0.08 1.33

PSCo 1.39 — 1.39

SPS 0.70 — 0.70

10 unchanged sentences

NSP-Minnesota $ 1.28 $ 0.04 $ 1.32

PSCo 1.33 — 1.33

1.26 0.08 1.33

SPS 0.70 0.01 0.71

2 unchanged sentences

Regulated utility (a)

3.52 0.14 3.66

Xcel Energy Inc.

2 unchanged sentences

(a) Amounts may not add due to rounding.

Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a $34 million loss due to a jury verdict in Denver County District Court awarding CORE lost power damages and other costs.

PSCo intends to file an appeal of this decision.

Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings.

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

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 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.

1 unchanged sentence

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

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

Given the non-recurring nature of this item, it has been excluded from ongoing earnings.

See Note 15 to the consolidated financial statements for further information.

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

Results of Operations

Diluted EPS for Xcel Energy at Dec.

Diluted Earnings (Loss) Per Share GAAP Diluted EPS GAAP Diluted EPS

Diluted Earnings (Loss) Per Share 2024 2023

NSP-Minnesota $ 1.41 $ 1.28

9 unchanged sentences

Workforce reduction expenses — 0.09

Sherco Unit 3 2011 outage refunds 0.06 —

Ongoing Diluted EPS (a)

4 unchanged sentences

2024 Comparison with 2023

Xcel Energy — GAAP diluted earnings were $3.21 per share compared to $3.17 per share in 2022 and ongoing diluted earnings were $3.35 per share in 2023, compared with $3.17 per share in 2022.

The increase in ongoing earnings per share was driven by increased recovery of infrastructure investments, higher sales and demand and lower O&M expenses, partially offset by higher depreciation and interest charges and unfavorable weather.

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.

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 $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023.

The change to ongoing earnings was driven by increased recovery of electric infrastructure investments, partially offset by increased interest charges and unfavorable weather.

PSCo — GAAP earnings decreased $0.07 per share and ongoing earnings was flat for 2023 compared to 2022.

Ongoing earnings primarily reflects higher recovery of infrastructure investment and lower O&M expenses, which were partially offset by increased depreciation, interest charges and unfavorable weather.

SPS — GAAP earnings increased $0.06 per share and ongoing earnings increased $0.07 per share for 2023 compared to 2022.

Ongoing earnings were largely impacted by regulatory rate outcomes, sales growth, partially offset by increased depreciation, interest charges and unfavorable weather.

NSP-Wisconsin — GAAP and ongoing earnings increased $0.02 per share for 2023 compared to 2022.

The increase in ongoing earnings was primarily a result of higher recovery of electric infrastructure investment, partially offset by unfavorable weather and, higher depreciation, O&M expenses and interest charges.

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.

Xcel Energy Inc.

and Other — Primarily includes financing costs and interest income at the holding company and earnings from EIP funds equity method investments.

Fluctuations from 2022 levels were largely attributable to increased interest rates.

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.

Changes in Diluted EPS

Components significantly contributing to changes in EPS:

Diluted Earnings (Loss) Per Share Dec.

GAAP and ongoing diluted EPS — 2022 $ 3.17

Components significantly contributing to changes in 2024 EPS compared with 2023:

Diluted Earnings (Loss) Per Share Twelve Months Ended Dec.

GAAP diluted EPS — 2023 $ 3.21

Components of change — 2024 vs.

Higher electric revenues, net of electric fuel and purchased power 0.07

Lower O&M expenses 0.06

Lower conservation and demand side management expenses (offset in electric revenues) 0.06

Higher other income (expense) 0.05

Lower taxes (other than income taxes) 0.04

Higher natural gas revenues, net of cost of natural gas sold and transported 0.03

Higher interest expense (0.14)

Higher depreciation and amortization (0.05)

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 depreciation and amortization (0.40)

Interest charges, net of AFUDC - debt (0.24)

Higher O&M expenses (0.13)

Sherco Unit 3 2011 outage refunds (0.06)

Other, net (0.11)

GAAP diluted EPS — 2024 $ 3.44

Workforce reduction expenses 0.09

Loss on Comanche Unit 3 litigation 0.05

Sherco Unit 3 2011 outage refunds 0.06

Ongoing diluted EPS — 2024 $ 3.50

ROE for Xcel Energy and its utility subsidiaries:

ROE GAAP ROE Ongoing ROE GAAP and Ongoing ROE

ROE GAAP ROE Ongoing ROE GAAP ROE Ongoing ROE

NSP-Minnesota 9.07 % 9.46 % 8.82 % 9.11 %

2 unchanged sentences

NSP-Wisconsin 8.98 8.98 10.38 10.67

Operating Companies 8.45 8.79 8.74

Utility Subsidiaries 8.55 8.69 8.45 8.79

Xcel Energy 10.42 10.61 10.33 10.79

4 unchanged sentences

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

However, electric decoupling mechanisms in Colorado (mechanism expired in September 2023) and electric sales true-up mechanisms in Minnesota and gas decoupling mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in those jurisdictions.

However, electric sales true-up and gas decoupling mechanisms 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.

37 unchanged sentences

Firm natural gas sales (1.1) 0.6 N/A (2.5) (0.2)

Annual weather-normalized electric sales growth (decline)

• NSP-Minnesota — Residential sales increased due to a 1.2% increase in customers outpacing declines in use per customer.

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

• PSCo — Residential sales increased due to increased use per customer and a 1.3% increase in customers.

The decline in C&I sales was attributable to decreased use per customer, primarily in the manufacturing sector.

• SPS — Residential sales growth was primarily attributable to a 0.7% increase in customers and increased use per customer.

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

• NSP-Wisconsin — The C&I sales decline was associated with lower use per customer, experienced primarily in the transportation and manufacturing sectors.

Annual weather-normalized natural gas sales growth (decline)

• Natural gas sales reflect 1.2% residential and 0.7% C&I customer growth and an increase in C&I use per customer at PSCo.

Partially offsetting these increases were lower use per residential customer in all jurisdictions.

Electric Margin

Electric margin is presented as electric revenues less electric fuel and purchased power expenses.

Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms.

As a result, changes in these expenses are generally offset in operating revenues.

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium.

These price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms.

In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.

Electric Revenues, Fuel and Purchased Power and Electric Margin

(Millions of Dollars) 2023 2022

2023 (Leap Year Adjusted)

NSP-Minnesota PSCo SPS NSP-Wisconsin Xcel Energy

Weather-normalized

Electric residential (0.1) % 0.7 % (1.5) % (1.8) % (0.1) %

Electric C&I (2.0) (1.4) 9.0 (1.8) 1.5

Total retail electric sales (1.4) (0.7) 7.1 (1.8) 1.0

Firm natural gas sales (1.7) — N/A (3.1) (0.7)

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.

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.

Electric Revenues

Electric fuel and purchased power (4,278) (5,005)

Electric margin $ 7,168 $ 7,118

Change in Electric Margin

Electric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality.

In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes.

(Millions of Dollars) 2024 vs.

Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI) $ 100

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

PTCs flowed back to customers (offset by lower ETR) (302)

Wholesale generation revenues (96)

Sherco Unit 3 2011 outage refunds (47)

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

Non-fuel riders 169

Sales and demand (a)

Wholesale transmission (net) 28

Revenue recognition of the Texas rate case surcharge (b)

Estimated impact of weather (net of decoupling/sales true-up) (51)

Conservation and demand side management (offset in expense) 102

PTCs flowed back to customers (offset by lower ETR) (28)

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

Other, net (42)

Total increase $ 50

(a) Sales excludes weather impact, net of partial decoupling in Colorado (mechanism expired in September 2023) and sales true-up mechanism in Minnesota .

(b) The decline in electric margin is due to the recognition of the Texas rate case outcome in the second quarter of 2022, which was largely offset by recognition of previously deferred costs.

Natural Gas Margin

Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported.

Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms.

As a result, changes in these expenses are generally offset in operating revenues.

Natural gas expense varies with changing sales and the cost of natural gas.

However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.

Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin

(Millions of Dollars) 2023 2022

Total decrease $ (299)

Natural Gas Revenues

Cost of natural gas sold and transported (1,456) (1,910)

Natural gas margin $ 1,189 $ 1,170

Change in Natural Gas Margin

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

(Millions of Dollars) 2024 vs.

Regulatory rate outcomes (CO, WI, MI) $ 50

Recovery of lower cost of natural gas $ (496)

Estimated impact of weather (net of decoupling) (35)

Retail sales decline (net of decoupling) (1)

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

Infrastructure and integrity riders 8

Other, net 18

Total increase $ 19

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.

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.

Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality.

These costs are generally recovered through various regulatory recovery mechanisms.

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

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

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

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased $47 million in 2023, primarily due to the impact of management cost containment efforts, the exit of our appliance repair services business and the change in deferred costs associated with the Texas Electric Rate Cases (offset in Electric revenues), offset by higher bad debt expenses, the impact of inflationary pressures, including labor, and timing of unplanned maintenance at generating plants.

Depreciation and Amortization — Depreciation and amortization increased $35 million for the year, primarily related to system expansion, offset by the change in deferred costs associated with the Texas Electric Rate Case and depreciation life extensions implemented in the Minnesota Electric Rate Case.

Taxes (other than Income Taxes) —Taxes (other than income taxes) decreased $31 million in 2023, primarily due to lower property tax expense (lower tax rates in Minnesota offset by increase in Colorado) and deferrals related to the Minnesota Electric Rate Case and Texas Electric Rate Case.

Other Income (Expense) — Other income (expense) increased $35 million for the year, primarily related to rabbi trust performance, which is primarily offset in employee benefit cost in O&M expenses.

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.

Interest Charges — Interest charges increased $200 million in 2024.

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.

Xcel Energy Inc.

5 unchanged sentences

financing costs $ (223) $ (174)

Venture Holdings (a)

Xcel Energy Inc.

taxes and other results (2) (12)

taxes and other results (a)

Total Xcel Energy Inc.

3 unchanged sentences

financing costs $ (0.40) $ (0.32)

Venture Holdings (a)

Xcel Energy Inc.

taxes and other results — (0.02)

taxes and other results (a)

Total Xcel Energy Inc.

and other costs $ (0.33) $ (0.31)

(a) Amounts include gains or losses associated with EIP investments.

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

Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc.

37 unchanged sentences

Mechanism Additional Information

CIP Rider (a)

Recovers costs of conservation and DSM programs.

Customer Protection Mechanisms MISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, and deferred tax asset refund are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers.

CIP Rider Recovers costs of conservation and DSM programs.

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

These costs are recovered through an annual cost-recovery mechanism.

Customer Protection Mechanisms MISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers.

Decoupling Measures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.

FCA Recovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).

GUIC 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.

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.

1 unchanged sentence

Includes a true-up process for difference between projected and actual costs.

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

Renewable Energy Rider Recovers cost of renewable generation in North Dakota.

RES Recovers cost of renewable generation in Minnesota.

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

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

These costs are recovered through an annual cost-recovery mechanism.

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.

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

The rate request was based on a ROE of 10.2%, a 52.5% equity ratio and forward test years.

In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan.

In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.

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 October 2023, the MPUC denied NSP-Minnesota’s request for reconsideration of certain aspects of the decision.

NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023.

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

The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion.

2023, the MPUC approved NSP-Minnesota’s request for interim rates, subject to refund, of approximately $51 million (implemented on Jan.

Next steps in the procedural schedule are expected to be as follows:

• Intervenor direct testimony:

April 19, 2024

• Rebuttal testimony:

• Evidentiary hearings:

July 10-12, 2024

• ALJ Report:

October 28, 2024

• MPUC Order Due:

March 14, 2025

2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC for an annual natural gas rate increase of approximately $8 million, or 9.4%.

The filing is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forecast test year with rate base of approximately $168 million.

NSP-Minnesota requested interim rates, subject to refund, of approximately $8 million to be implemented on March 1, 2024.

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

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

The opinion is currently pending further action from the MPUC.

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

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

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

A decision is expected in 2026.

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

The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%.

In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb.

Nuclear Power Operations

5 unchanged sentences

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 PI 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 at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.

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.

2 unchanged sentences

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 PI nuclear generating plants.

Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2.

In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.

In October 2023, the MPUC issued an order approving NSP-Minnesota’s application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.

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

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

In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No.

DPR-22, Accession No.

ML24310A345).

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

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

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

Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.

7 unchanged sentences

Pipeline safety compliance.

Michigan Public Service Commission Retail rates, services and other aspects of electric and natural gas operations.

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.

18 unchanged sentences

NSP-Wisconsin recovers these costs from customers.

Recently Concluded Regulatory Proceedings

Wisconsin Rate Case — In 2023, NSP-Wisconsin filed a Wisconsin rate case seeking a revised electric increase of $25 million and a natural gas increase of $7 million.

The filing was based on a 2024 forecast test year, a ROE of 10.25%, an equity ratio of 52.5% and a forecasted average net rate base of approximately $2.1 billion for the electric utility and $284 million for the natural gas utility.

In December 2023, the PSCW approved a ROE of 9.8% and an equity ratio of 52.5% as well as a rate increase of approximately $1 million for the electric utility.

Adjustments to NSP-Wisconsin’s rate request included removal of a proposed residential affordability program and other earnings neutral adjustments and fuel and purchased power costs.

The PSCW also approved a $5 million rate increase for the natural gas utility in 2024.

The new rates were implemented on Jan.

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.

Pending and Recently Concluded Regulatory Proceedings

2022 Upper Midwest IRP Resource Acquisition — Following the MPUC’s approval of NSP-Minnesota and NSP-Wisconsin’s latest IRP in April 2022, NSP-Minnesota and NSP-Wisconsin have been engaged in multiple resource acquisition processes and proceedings to meet the need identified in the IRP for the NSP System.

• In August 2022, NSP-Minnesota and NSP-Wisconsin jointly filed an RFP seeking at least 900 MW of solar or solar plus storage capacity.

In May 2023, NSP-Minnesota filed a recommended portfolio, which proposed an additional 250 MW of self-build solar generation at the site of our retiring Sherco coal units and a 100 MW solar PPA located in Wisconsin as part of the resource plan RFP.

In September 2023, the MPUC approved the request for 350 MW, subject to a cost cap based on projected costs for the Sherco solar project.

• In the second quarter of 2023, NSP-Minnesota initiated the process with the MPUC for acquisition of 800 MW of firm dispatchable resources.

In January 2024, NSP-Minnesota and other companies submitted proposed resources.

NSP-Minnesota expects a decision by the fourth quarter of 2024.

• In July 2023, NSP-Wisconsin issued an RFP seeking approximately 650 MW of solar and/or solar plus storage development assets that will be developed in the 2027-2029 timeframe to replace the capacity from the retiring King Generating Station.

The RFP closed in September 2023 and bids are being evaluated.

• In October 2023, NSP-Minnesota issued an RFP seeking approximately 1,200 MW of wind development assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities.

The RFP closed in December 2023 and the NSP-Minnesota expects to file for approval of recommended projects by mid-2024.

2024 Upper Midwest Energy Plan — In February 2024, NSP-Minnesota filed its resource plan with the MPUC.

Key components of the plan include the following:

• Reduced carbon emissions by more than 80%, potentially up to 88%, by 2030.

• Extends the operation of Prairie Island and Monticello nuclear plants through the early 2050s.

• Adds 3,600 MW of new wind and solar resources by 2030.

• Adds 600 MW of battery energy storage by 2030.

• Adds more than 2,200 MW of dispatchable resources by 2030.

NSP-Minnesota anticipates a MPUC decision in 2025.

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.

• In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities.

The RFP closed in December 2023.

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

• In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit.

Bids are currently under evaluation;

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

Purchased Power and Transmission Services

25 unchanged sentences

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.

Decoupling Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes (pilot program ended Sept.

2023, with amortization of previously deferred amounts expected through 2026).

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

ECA Recovers fuel and purchased energy costs.

Electric Commodity Adjustment Recovers fuel and purchased energy costs.

Short-term sales margins are shared with customers.

The ECA is revised quarterly.

PTCs earned for owned wind 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.

6 unchanged sentences

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.

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

Pending and Recently Concluded Regulatory Proceedings

Colorado Electric Rate Case — In 2022, PSCo filed a Colorado electric rate case seeking a revised net increase of $253 million.

The total request reflected a $303 million increase, which includes $50 million of authorized costs previously recovered through various rider mechanisms.

The request was based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of $11.3 billion.

In September 2023, the CPUC approved a settlement between PSCo and various parties, which included the following terms:

• Retail revenue increase (excluding rider roll-ins) of $95 million (2.96%), based on a 2022 historic test year using year-end rate base with forward looking known and measurable adjustments.

• Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).

• Termination of the revenue decoupling pilot.

• Continuation of previously authorized trackers and deferrals.

Rates became effective in September 2023.

Colorado Resource Plan — In August 2022, the CPUC approved a settlement for the Colorado Resource Plan, which provides for an expected carbon reduction and the retirement of PSCo’s remaining coal plant by the end of 2030.

In September 2023 (updated in October 2023), PSCo filed its recommended Preferred Portfolio of resources, which proposed a total of 7,521 MW of generation resources, including 4,716 owned MW and 2,805 purchased power MW.

The filing also included several other alternative portfolios.

In December 2023, the CPUC approved an alternative portfolio of 5,835 MW.

The decision provides an opportunity to assess timing and levels of incremental renewable resources in the Just Transition Plan filing expected to be submitted by June 1, 2024.

Approved portfolio includes the following resources:

Generation Resource (in MW) Company Owned PPAs Total

Wind Resources 1,325 375 1,700

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.

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

Wind 7,250 2,800

Solar 3,077 1,200

Storage 500 1,348 1,848

Natural Gas 450 219 669

Natural gas combustion turbine 1,575 1,400

Storage (long duration) 1,600 —

Other storage 450 —

Total 13,952 5,400

PSCo expects to invest approximately $4.8 billion in generation resources under the alternative portfolio for the benefit of its customers and achieving the state’s clean energy goals.

The CPUC did not approve the May Valley to Longhorn Transmission Line, which was estimated at $250 million.

In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs.

These PIMs will be further defined in the written order and related proceedings throughout 2024.

In February 2024, PSCo filed an ARRR to seek approval for an updated portfolio, reflecting inclusion of certain back-up bids and clarifications of the application of PIMs.

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, or an approximately 9.5% increase in the average residential customer bill.

The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% and a $4.2 billion retail rate base which includes projected capital additions through Dec.

PSCo has requested a proposed effective date of Nov.

PSCo has proposed to defer collection of the increased rates until Feb.

15, 2025 (following the expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.

The request supports fundamental infrastructure investments to serve customers, consistent with PSCo’s obligation to provide safe, reliable service while enabling PSCo to continue to be a leader of the clean energy transition in partnership with the CPUC to achieve clean heat goals.

Revenue Request (millions of dollars)

Changes since 2022 rate case:

Plant related investments (a)

Operations and maintenance, amortization and other expenses 23

Property tax expense 10

Sales growth (7)

Total base revenue request $ 171

(a) Includes approximately $32 million as a result of the increase in ROE from 9.2% to 10.25%.

ECA Fuel Recovery — In December 2022, PSCo filed to recover $123 million of under-recovered 2022 fuel costs over two quarters.

In December 2022, the CPUC found that the $123 million should be removed from the proposed ECA rates, and required PSCo to file a separate application to recover these costs.

In 2023, PSCo submitted interim ECA filings to recover $70 million and $25 million, respectively, of the 2022 under-recovered costs.

In the third quarter, PSCo and CPUC Staff filed a settlement allowing for collection of the remaining amount, which after final adjustments was $37 million.

In December 2023, the ALJ issued a recommended decision approving the settlement in full.

Recovery of costs is expected to begin in the second quarter of 2024.

Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and was signed into law.

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:

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 management plan, 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 are 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 by Jan.

The CPUC issued a request for initial comments on a potential mechanism under which gas utilities would share a percentage, subject to an annual cap, of cost changes in the GCA.

A formal rulemaking is expected to commence in the first half of 2024.

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.

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.

Purchased Power and Transmission Service Providers

4 unchanged sentences

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.

Energy Markets — PSCo joined the SPP Western Energy Imbalance Service Market in April 2023.

This market is an incremental step in the participation in an organized wholesale market.

Energy imbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids.

The result improves balancing supply and demand 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.

26 unchanged sentences

Fuel and Purchased Power Cost Adjustment Clause Adjusts monthly to recover actual fuel and purchased power costs in New Mexico.

Generation Cost Recovery Rider Allows recovery of investment in power generation facilities outside of a base rate case proceeding.

Purchased Power Capacity Cost Recovery Factor Allows recovery of purchased power capacity costs not included in Texas rates.

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

Renewable Portfolio Standards Recovers deferred costs for renewable energy programs in New Mexico.

3 unchanged sentences

Pending and Recently Concluded Regulatory Proceedings

2022 New Mexico Electric Rate Case — In 2022, SPS filed a New Mexico electric rate case seeking a revised revenue increase of $75 million.

The request was based on a ROE of 10.75%, an equity ratio of 54.7%, a future test year ending June 30, 2024 and rate base of $2.4 billion.

In October 2023, the NMPRC approved a settlement between SPS, NMPRC Staff, and various parties, which included the following terms:

• Base rate revenue increase of $33 million, based on the filed future test year.

• ROE of 9.5%.

• Equity ratio of 54.7%.

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

Rates went into effect in October 2023.

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

The request was based on a ROE of 10.65%, an equity ratio of 54.6% and rate base of $3.6 billion.

SPS requested a surcharge from July 13, 2023 through the effective date of new base rates.

In December 2023, SPS, PUCT Staff and intervenors filed a black box settlement.

Key terms include:

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.

• 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.

A PUCT decision is expected in the first half of 2024.

SPS and LP&L Termination — SPS and LP&L were parties to a 25-year, 170 MW partial requirements contract serving LP&L.

In May 2021, SPS and LP&L finalized a settlement which terminated the contract upon LP&L’s move from the SPP to the ERCOT.

Based on the approved de-escalation clause, LP&L paid SPS $66 million in January 2024 to the benefit of SPS’ remaining customers.

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

A decision from PUCT and NMPRC is expected in mid-2024.

The second portion of the portfolio includes a November 2023 filing for the approval of PPAs including 48 MW of battery energy storage and 230 MW of existing gas generation.

Regulatory decisions on these PPA agreements are expected in Q3 2024.

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

Based on load forecast scenarios, SPS’ initial IRP modeling projects a total resource need ranging from approximately 5,300 MW to 10,200 MW by 2030.

Upon acceptance of the IRP, SPS expects to issue an RFP for new generation in mid-2024.

The RFP will be evaluated in the latter half of 2024 with portfolio selection expected in early 2025.

• 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

The procedural schedule is as follows:

• Intervenor testimony:

February 28, 2025

• Staff testimony:

March 7, 2025

• Rebuttal testimony:

March 17, 2025

March 25-26, 2025

A PUCT decision is expected in the summer of 2025.

Purchased Power Arrangements and Transmission Service Providers

4 unchanged sentences

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

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.

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.

3 unchanged sentences

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

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

Manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping.

Inflationary pressures, labor shortages, and the impact of geopolitical events have further exacerbated these disruptions.

Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.

Additionally, certain products, components, and equipment, particularly in renewables categories, originate in countries that could face tariffs, fines, or restrictions from government or other regulatory bodies and present a cost and supply risk until there is sufficient capacity and supply base with adequate capacity to meet US needs.

Electric Meters and Transformers

Supply chain issues associated with semiconductors delayed the availability of AMI meters, which led to a reduced number of meters deployed in 2022.

Xcel Energy saw significant improvement in meter availability in 2023 and we expect normal conditions in 2024 and going forward.

Xcel Energy expects to complete AMI meter deployment in 2025.

Additionally, the availability of certain transformers is an industry-wide issue that has significantly impacted and in some cases resulted in delays to projects and new customer connections.

Proposed governmental actions related to transformer efficiency standards may compound these delays in the future.

Xcel Energy continues to seek alternative suppliers and prioritize work plans to mitigate the impacts of supply constraints.

Solar Resources

In August 2023, the U.S.

Department of Commerce completed its anti-circumvention investigation.

It concluded that CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia would be subject to incremental tariffs ranging from 50% to 250%.

These countries account for more than 80% of CSPV panel imports.

An interim stay on tariffs remains in effect until June 2024.

Many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo.

Further policy action, a change in the interim stay of tariffs, or other restrictions on solar imports (e.g., due to implementation of the Uyghur Forced Labor Protection Act) or disruptions in solar imports from key suppliers could impact project timelines and costs.

New Technology and Government Grants

Hydrogen Hub Grant

In October 2023, t he DOE selected the Heartland Hydrogen Hub, including multiple clean hydrogen projects from Xcel Energy, for award negotiations to receive up to $925 million.

The Heartland Hydrogen Hub is one of seven selected to receive DOE funding.

The hub includes Xcel Energy, Marathon Petroleum Corporation and TC Energy, in collaboration with the University of North Dakota’s Energy & Environmental Resource Center, to produce and use low-carbon hydrogen at commercial scale in Minnesota, Wisconsin, South Dakota, North Dakota and Montana.

The hub aims to reduce carbon emissions by more than 1 million metric tons per year.

Xcel Energy expects to receive a large portion of the federal award for its projects within the hub, subject to negotiations.

In its application, Xcel Energy proposed investing up to $2 billion over a decade for clean hydrogen producing equipment and infrastructure, representing 75% of full program costs for the company’s portion of the hub.

Project detailed design will begin after the Heartland Hydrogen Hub finishes award negotiations.

Project development will likely continue through 2035.

Form Energy Long Duration Storage Grant

In September 2023, the DOE awarded Xcel Energy a $70 million grant to support our two 10 MW, 100-hour battery pilots with Form Energy.

Xcel Energy expects to develop a 10 MW 100-hour-battery storage unit at the Sherco retiring coal plant site in Minnesota and the Comanche retiring coal plant site in Colorado.

Combined with grants from Breakthrough Energy’s Catalyst Fund, Xcel Energy has secured $90 million to support these pilots, which will reduce the costs of the projects for our customers.

Long duration energy storage systems are critical to achieve 100% carbon free generation and strengthen the grid from the variability of renewable energy.

Wildfire/Extreme Weather Grant

In October 2023, the DOE awarded Xcel Energy $100 million to support projects to mitigate the threat of wildfires and ensure resiliency of the grid through extreme weather.

Xcel Energy plans to match the grant with $140 million of investment.

The projects will take a number of steps to boost grid resiliency, including adding fire-resistant coatings to 6,000 wood poles, improving equipment safety features in power lines and electric vehicle chargers in high fire risk conditions, moving high-risk distribution circuits underground, and enhancing vegetation management.

They will also build on current programs using emerging technology, such as drones aided by artificial intelligence that inspect power lines for safety, wind strength testing, satellite identification of trees that pose a risk and modeling software to predict how fires would spread.

Joint Targeted Interconnection Queue (JTIQ) Grant

In October 2023, the DOE awarded a $464 million grant to Xcel Energy and several other utilities for five JTIQ projects.

The projects are part of a collaboration between MISO and SPP that will help to fund the construction of high-voltage transmission lines that improve reliability and resolve constraints in the transmission system for up to 30 gigawatts of new generation.

Xcel Energy is part of two of these project awards.

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 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.

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.

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.

Critical Accounting Policies and Estimates

38 unchanged sentences

Pension assumptions are continually reviewed.

31, 2023, Xcel Energy set the rate of return on assets used to measure pension costs at 6.93%, which is unchanged from the rate set at Dec.

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.

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

31, 2023, which is unchanged from the rate set in 2022.

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

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 5.49% and 5.54% at Dec.

31, 2023, respectively.

This represents a 31 basis point and 26 basis point decrease, respectively, from 2022.

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 uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations.

3 unchanged sentences

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 2023 pension costs:

If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2025 pension costs, net of the effects of regulation:

Pension Costs

(Millions of Dollars) +1% -1%

Rate of return (a)

Discount rate (a)

(a) These costs include the effects of regulation.

Rate of return $ (12) $ 24

Discount rate

Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits.

4 unchanged sentences

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.

Funding contributions in 2023 were $50 million and will remain relatively consistent in future years, with the exception of 2024, when Xcel Energy plans on making a higher contributions as a result of the Voluntary Retirement Program offering in 2023.

Investment returns were more than the assumed levels in 2023 and 2021, but were less than the assumed levels in 2022.

Funding contributions in 2024 were $100 million and will be $125 million in 2025.

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.

The pension cost calculation uses a market-related valuation of pension assets.

3 unchanged sentences

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 2024 is primarily due to reductions in the effects or regulations.

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

Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2022 - 2025:

10 unchanged sentences

Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.

• In 2021, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 2021 pension settlement accounting expense.

Escrow accounting treatment was also approved for ongoing pension and other post-employment benefit expenses, including settlement charges.

• 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 that adjusts the annual post-retirement benefits amount to zero in order to match the amount collected in rates.

• 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.

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 2024.

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

7 unchanged sentences

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 asset.

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 $2.5 billion in 2024 and $2.1 billion in 2023.

3 unchanged sentences

The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material.

The 2022 - 2024 Nuclear Decommissioning Study and Assumptions were approved by the MPUC in August 2022.

The MPUC ordered the next triennial decommissioning study be filed by December 1, 2024, allowing for four years between filings.

In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed.

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 approved retirement dates which can be different than the expiration dates of each unit’s operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for PI’s Unit 1 and 2, respectively).

In April 2022, the Company received approval from the MPUC, in the Integrated Resource Plan, to pursue extending the operating life of the Monticello Nuclear Generating Plant by ten years from 2030 to 2040.

This life extension is subject to NRC approval of Monticello’s nuclear license extension request.

The retirement dates of the Prairie Island Unit 1 and Unit 2 remain unchanged, 2033 and 2034 respectively.

The estimated timing of the decommissioning activities is based upon the 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 2101.

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.

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.

1 unchanged sentence

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 3.2% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors calculated by Goldman Sachs Asset Management.

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.

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.

10 unchanged sentences

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

Loss Contingencies – Marshall Fire

The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire are subject to uncertainty.

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 an unfavorable outcome and the ability to make a reasonable estimate of the amount of loss.

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 the wildfire, the extent and magnitude of potential damages, and the status of investigations and legal proceedings are considered.

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

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.

See Note 12 accompanying the consolidated financial statements for additional information.

Derivatives, Risk Management and Market Risk

22 unchanged sentences

$ (12) $ (4) $ (8) $ 2 $ (22)

$ (10) $ (4) $ (5) $ (1) $ (20)

Options Maturity

4 unchanged sentences

$ — $ — $ 20 $ — $ 20

$ 4 $ — $ 9 $ 8 $ 21

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

3 unchanged sentences

Fair value of commodity trading net contracts outstanding at Jan.

1 $ (10) $ (33)

Contracts realized or settled during the period — (2)

1 unchanged sentence

Fair value of commodity trading net contracts outstanding at Dec.

31 $ 1 $ (10)

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.

Market price movements can exceed 10% under abnormal circumstances.

Xcel Energy’s’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR.

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.

4 unchanged sentences

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.

NSP-Minnesota is scheduled to take delivery of approximately 29% of its average enriched nuclear material requirements from Russia through 2030.

Given the evolving situation in Ukraine and its global impacts, we have entered into additional new contracts that cover potential supply interruptions of nuclear material from Russia.

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.

29 unchanged sentences

Non-cash transactions 222

Changes in deferred taxes 284

Changes in working capital (783)

1 unchanged sentence

Cash provided by operating activities — 2024 $ 4,641

Net cash provided by operating activities increased by $1,395 million for 2023 as compared to 2022.

The increase was largely due to continued collections of prior year deferred net natural gas, fuel and purchased energy costs, as well as the impact of decreased natural gas prices on accounts payable and receivables.

Net cash provided by operating activities decreased by $686 million for 2024 as compared to 2023.

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.

Investing Cash Flows

6 unchanged sentences

Net cash used in investing activities increased by $1,502 million for 2024 as compared to 2023.

The increase in capital expenditures was largely due to continued system expansion.

The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.

Financing Cash Flows

2 unchanged sentences

Components of change — 2024 vs.

Higher debt issuances, net of repayments 80

Lower proceeds from issuance of common stock (52)

Higher long-term debt issuances, net of repayments 1,512

Higher proceeds from issuance of common stock 847

Higher dividends paid to shareholders (83)

1 unchanged sentence

Cash provided by financing activities — 2024 $ 2,837

Net cash provided by financing activities decreased by $49 million for 2023 as compared to 2022.

The decrease was largely related to the amount/timing of debt issuances and repayments.

Net cash provided by financing activities increased by $2,220 million for 2024 as compared to 2023.

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.

19 unchanged sentences

Total contractual cash obligations $ 57,645 $ 5,352 $ 5,008 $ 4,538 $ 42,747

(a) Included in operating lease obligations are $244 million, $461 million, $269 million and $259 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases.

(a) Included in operating lease obligations are $240 million, $372 million, $166 million and $199 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.

4 unchanged sentences

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

(c) Amounts exclude approximately $1 billion of minimum payments related to SPS’ extension of a non-lease PPA that otherwise expires in 2026, pending PUCT and NMPRC approvals to extend the agreement to 2039.

Approval processes are expected to conclude in 2024.

(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 and incremental capital forecasts:

Capital Expenditures — Base capital expenditures for Xcel Energy for 2025 through 2029:

Actual Base Capital Forecast (Millions of Dollars)

9 unchanged sentences

By Function 2024 2025 2026 2027 2028 2029 2025 - 2029 Total

Electric transmission $ 1,320 $ 1,710 $ 2,020 $ 2,450 $ 2,850 $ 2,470 $ 11,500

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

Electric transmission 1,720 2,260 2,860 2,740 2,390 2,310 12,560

Renewables 1,130 3,360 1,400 260 — — 5,020

3 unchanged sentences

Total base capital expenditures $ 7,650 $ 11,000 $ 9,840 $ 8,750 $ 7,570 $ 7,840 $ 45,000

The base plan does not include potential renewable generation additions at the NSP System, SPS and PSCo, which could result in additional capital expenditures of approximately $5 billion.

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.

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 (e.g., federal clean energy and 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 2028 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes.

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 2029 — 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 2025 through 2029 (includes the impact of tax credit transferability):

48 unchanged sentences

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

Credit Facility Agreements — 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.

Credit Facility Agreements — As of Feb.

24, 2025, Xcel Energy Inc.

11 unchanged sentences

(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.

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.

4 unchanged sentences

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 2025 financing plans reflect the following:

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

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

Xcel Energy Inc.

Senior Unsecured Notes $ 900 First Quarter 10 Year

PSCo First Mortgage Bonds 1,200 Second Quarter 10 Year and 30 Year

NSP-Minnesota First Mortgage Bonds 700 First Quarter 30 Year

SPS First Mortgage Bonds 550 Second Quarter 30 Year

NSP-Wisconsin First Mortgage Bonds 400 Second Quarter 30 Year

Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its at-the-market 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.

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

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

2 unchanged sentences

Key assumptions as compared with 2024 actual levels unless noted:

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

• Normal weather patterns for the remainder of the year.

• Weather-normalized retail electric sales are projected to increase 2% to 3%.

• Weather-normalized retail firm natural gas sales are projected to be flat.

• 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.

• 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 $260 million to $270 million (net of PTCs).

• O&M expenses are projected to increase 1% to 2%.

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

• Depreciation expense is projected to increase approximately $210 million to $220 million.

2 unchanged sentences

• AFUDC - equity is projected to increase $110 million to $120 million.

• ETR is projected to be ~(4%) to (6%) .

The negative ETR is largely offset by PTCs flowing back to customers in the capital riders and fuel mechanisms and is largely earnings neutral.

The projected ETR does not reflect the potential impact of nuclear PTCs, which are also expected to flow back to customers.

(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.

2 unchanged sentences

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 5% to 7% based off of a 2023 actual ongoing earnings base of $3.35 per share.

• 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 annual dividend increases of 4% to 6%.

4 unchanged sentences

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