What changed in this filing

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Item 7. Management’s Discussion and Analysis

2024-02-21 compared with 2023-02-23 · 381 added, 394 removed, 665 unchanged (54% of the section changed)

2 unchanged sentences

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, ongoing earnings and ongoing diluted EPS.

Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that are adjusted from measures calculated and presented in accordance with GAAP.

Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that is adjusted from measures calculated and presented in accordance with GAAP.

Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors.

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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.

We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries.

For the years ended Dec.

31, 2022 and 2021, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.

These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

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

(Millions of Dollars) 2023 2022

GAAP net income $ 1,771 $ 1,736

Loss on Comanche Unit 3 litigation 35 —

Workforce reduction expenses 72 —

tax effect of adjustments (27) —

Ongoing earnings $ 1,851 $ 1,736

Twelve Months Ended Dec.

Diluted Earnings (Loss)

Per Share GAAP Diluted EPS Impact of Adjustments Ongoing Diluted EPS

NSP-Minnesota $ 1.28 $ 0.04 $ 1.32

1.26 0.08 1.33

SPS 0.70 0.01 0.71

NSP-Wisconsin 0.25 — 0.25

Earnings from equity method investments — WYCO 0.04 — 0.04

Regulated utility (a)

3.52 0.14 3.66

Xcel Energy Inc.

and Other (0.31) — (0.31)

$ 3.21 0.14 $ 3.35

Twelve Months Ended Dec.

Diluted Earnings (Loss)

Per Share GAAP Diluted EPS Impact of Adjustments Ongoing Diluted EPS

NSP-Minnesota $ 1.23 $ — $ 1.23

PSCo 1.33 — 1.33

SPS 0.64 — 0.64

NSP-Wisconsin 0.23 — 0.23

Earnings from equity method investments — WYCO 0.04 — 0.04

Regulated utility (a)

Xcel Energy Inc.

and Other (0.29) — (0.29)

$ 3.17 — $ 3.17

(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.

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

Xcel Energy initiated a voluntary retirement program, under which approximately 400 eligible non-bargaining employees retired.

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

Total 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.

Results of Operations

Diluted EPS for Xcel Energy at Dec.

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

PSCo $ 1.33 $ 1.22

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

NSP-Minnesota $ 1.28 $ 1.23

PSCo 1.26 1.33

SPS 0.70 0.64

4 unchanged sentences

and Other (0.31) (0.29)

GAAP Diluted EPS (a)

Loss on Comanche Unit 3 litigation 0.05 —

Workforce reduction expenses 0.09 —

Ongoing Diluted EPS (a)

$ 3.35 $ 3.17

3 unchanged sentences

2023 Comparison with 2022

Xcel Energy — GAAP and ongoing earnings increased $0.21 per share for 2022.

The increase was driven by regulatory outcomes, partially offset by higher depreciation, O&M expenses and interest charges.

Costs for natural gas significantly increased in 2022 due to market conditions.

However, 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 revenues are offset by the related variation in costs).

PSCo — Earnings increased $0.11 per share for 2022, driven by regulatory outcomes and favorable weather.

Higher revenues were partially offset by higher depreciation, O&M expenses and interest charges.

NSP-Minnesota — Earnings increased $0.11 per share for 2022 compared to 2021, driven by regulatory rate outcomes, partially offset by additional depreciation and O&M expenses.

SPS — Earnings increased $0.05 per share for 2022, largely related to regulatory rate outcomes, strong sales growth and favorable weather, partially offset by higher depreciation and O&M expenses.

NSP-Wisconsin — Earnings increased $0.03 per share for 2022 compared to 2021.

The increase is due to regulatory rate outcomes and sales growth, partially offset by higher depreciation and O&M expenses.

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.

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 $0.05 per share and ongoing earnings increased $0.09 per share for 2023 compared to 2022.

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.

Xcel Energy Inc.

and Other — Earnings decreased $0.07 per share year-to-date due to higher interest charges and decreased earnings from EIP investments.

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.

Changes in Diluted EPS

4 unchanged sentences

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

Lower ETR (a)

Higher depreciation and amortization (0.40)

Higher O&M expenses (0.24)

Higher interest expense (0.14)

Higher taxes (other than income taxes) (0.08)

Higher depreciation and amortization (0.05)

Workforce reduction expenses (0.09)

Loss on Comanche Unit 3 litigation (0.05)

Other (net) 0.06

GAAP and ongoing diluted EPS — 2022 $ 3.17

(a) Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.

GAAP diluted EPS — 2023 $ 3.21

Workforce reduction expenses 0.09

Loss on Comanche Unit 3 litigation 0.05

Ongoing diluted EPS — 2023 $ 3.35

ROE for Xcel Energy and its utility subsidiaries:

ROE GAAP and Ongoing ROE GAAP and Ongoing ROE

PSCo 8.23 % 8.23 %

ROE GAAP ROE Ongoing ROE GAAP and Ongoing ROE

NSP-Minnesota 8.82 % 9.11 % 8.76 %

PSCo 7.32 7.77 8.23

SPS 9.80 9.98 9.36

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

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

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.

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.

22 unchanged sentences

Firm natural gas (0.010) 0.037 (0.047)

Decoupling $ 0.013 $ — $ 0.013

Gas total $ 0.003 $ 0.037 $ (0.034)

Total $ 0.009 $ 0.114 $ (0.105)

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

PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy

NSP-Minnesota PSCo SPS NSP-Wisconsin Xcel Energy

Electric residential (0.5) % (4.0) % (3.0) % (2.6) % (2.3) %

2 unchanged sentences

Firm natural gas sales (12.0) (1.5) N/A (12.6) (5.7)

PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy

NSP-Minnesota PSCo SPS NSP-Wisconsin Xcel Energy

Weather-normalized

3 unchanged sentences

Firm natural gas sales — 2.3 N/A (0.4) 1.4

Weather-normalized electric sales growth (decline) — year-to-date

• PSCo — Residential sales declined due to decreased use per customer, partially offset by a 1.1% increase in customers.

C&I sales decline was attributable to decreased use per customer, primarily in the manufacturing sector (largely due to an alternative generation arrangement with a significant customer), partially offset by strong small C&I sales in the food services and health care sectors.

• NSP-Minnesota — Residential sales decline reflects a decreased use per customer, partially offset by a 1.1% increase in customers.

Growth in C&I sales was primarily due to higher use per customer, particularly in the manufacturing, real estate and leasing, and food service sectors.

• SPS — Residential sales growth was primarily attributable to a 0.9% increase in customers, partially offset by lower use per customer.

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 — C&I sales growth was associated with higher use per customer, experienced primarily in the transportation and manufacturing sectors.

Weather-normalized natural gas sales growth (decline) — year-to-date

• Natural gas sales reflect growth in NSP-Minnesota and NSP-Wisconsin attributable primarily to increased residential use per customer and customer growth as well as increases in C&I sales due to higher use per customer.

These increases were offset by a reduction in PSCo natural gas sales, primarily driven by declines in residential use per customer.

• 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

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(Millions of Dollars) 2023 vs.

Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin) $ 506

Revenue recognition for the Texas rate case surcharge (a)

Sales and demand (b)

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

Non-fuel riders 89

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) (43)

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

1 unchanged sentence

Total increase $ 50

(a) Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs.

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

(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

11 unchanged sentences

(Millions of Dollars) 2023 vs.

Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, North Dakota) $ 61

Estimated impact of weather 46

Conservation revenue (offset in expenses) 13

Infrastructure and integrity riders 9

Winter Storm Uri disallowances (20)

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

Estimated impact of weather (net of decoupling) (25)

Other (net) (6)

1 unchanged sentence

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $170 million year-to-date, due to the following approximately equal drivers:

inflation and impacts of supply chain constraints;

operational activities (vegetation management, repairs/maintenance and storms);

costs for technology and customer programs;

insurance-related costs;

recognition of previously deferred amounts related to the 2021 Texas rate case;

Depreciation and Amortization — Depreciation and amortization increased $292 million year-to-date.

The increase was primarily driven by capital investment, recognition of previously deferred costs related to the Texas Electric Rate Case and several wind farms going into service.

Other Income (Expense) — Other income (expense) decreased $18 million year-to-date, largely related to rabbi trust performance, which is primarily offset in O&M expenses (employee benefit costs).

Earnings from Equity Method Investments — Earnings from equity method investments decreased $26 million year-to-date.

The year-to-date change was largely attributable to the performance of the EIP funds, which invest in energy technology companies.

Interest Charges — Interest charges increased $111 million year-to-date.

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.

Interest Charges — Interest charges increased $102 million in 2023.

The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.

Income Taxes — Income tax benefit increased $65 million year-to-date.

The year-to-date increase was primarily driven by an increase in wind PTCs due to greater production at existing wind farms, several new wind farms going into service and an increase in the PTC rate partially offset by higher pretax earnings.

Xcel Energy Inc.

2 unchanged sentences

and its nonregulated businesses:

Contribution (Millions of Dollars)

(Millions of Dollars) 2023 2022

Xcel Energy Inc.

5 unchanged sentences

and other costs $ (173) $ (160)

Contribution (Diluted Earnings (Loss) Per Share)

(Diluted Earnings (Loss) Per Share) 2023 2022

Xcel Energy Inc.

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Decisions by these regulators can significantly impact Xcel Energy’s results of operations and credit quality.

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

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

NSP-Minnesota

21 unchanged sentences

CIP Rider (a)

Recovers costs of conservation and DSM programs in Minnesota.

Environmental Improvement Rider Recovers costs of environmental improvement projects in Minnesota.

Renewable Development Fund Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.

RES Recovers cost of renewable generation in Minnesota.

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

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

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

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.

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.

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

Purchased Gas Adjustment Provides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service.

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

The statute authorizing the GUIC Rider is set to expire June 30, 2023.

Sales True-up NSP-Minnesota has historically had a sales true-up mechanism for all electric customer classes which ended in 2021.

We are requesting implementation of a new sales true-up mechanism for 2022 - 2024.

These mechanisms mitigate the impact of changes to sales levels as compared to a baseline.

Renewable Development Fund 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.

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.

1 unchanged sentence

Pending and Recently Concluded Regulatory Proceedings

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

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

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.

The revised request is detailed as follows:

(Amounts in Millions) 2022 2023 2024 Total

Rate request (annual increase) $ 234 $ 94 $ 170 $ 498

Rate base 10,923 11,425 11,902 N/A

In 2022, several parties filed testimony with various recommendations.

The DOC provided the following recommendations in surrebuttal testimony.

2022 2023 2024

NSP-Minnesota’s filed base revenue request $ 396 $ 546 $ 677

Recommended adjustments:

Rate base and rate of return (72) (65) (65)

MISO capacity credits (66) (112) (111)

Sales forecast update (51) — —

Monticello and wind farm life extension (21) (54) (51)

PTC forecast (28) (1) (1)

Property tax (14) (23) (34)

Prepaid pension asset and liability (13) (21) (32)

O&M expenses (37) (39) (44)

Sherco 3 and King remaining life — 29 28

Other, net (23) (33) (43)

Total adjustments (325) (319) (353)

Total proposed revenue change $ 71 $ 227 $ 324

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

• MPUC Order:

June 30, 2023.

2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of $36 million, or 6.6%.

The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate base of $934 million.

In December 2021, the MPUC approved an interim rate increase of $25 million, subject to refund, effective Jan.

In October 2022, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following key terms:

• Base rate revenue increase of $21 million, with a true up to weather normalized actual sales for 2022.

• Revenue decoupling mechanism.

• Symmetrical property tax true-up.

• ROE of 9.57%.

• Equity ratio of 52.5%.

In December 2022, the ALJ recommended MPUC approval of the settlement.

A MPUC decision is expected in the first half of 2023.

2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.5%.

The filing is based on a ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and rate base of $124 million.

Interim rates of $7 million, subject to refund, were implemented on Nov.

In May 2022, NSP-Minnesota and NDPSC Staff reached a settlement, which reflects a rate increase of $5 million, based on a 9.8% ROE and 52.54% equity ratio.

In October 2022, the NDPSC approved the settlement and final rates were implemented on Nov.

South Dakota Electric Rate Case — In June 2022, NSP-Minnesota filed a South Dakota electric rate case seeking a revenue increase of approximately $44 million.

The filing is based on a 2021 historic test year adjusted for certain known and measurable changes for 2022 and 2023, a ROE of 10.75%, rate base of approximately $947 million and an equity ratio of 53%.

Interim rates were implemented on Jan.

Final rates are expected to be approved by the SDPUC in mid-2023.

Wind Repowering — In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects.

Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval.

While the capital costs have increased, the passage of the IRA and other changes result in a levelized cost of energy that is approximately 30% lower than the original approval.

In October 2022, NSP-Minnesota filed a request with the MPUC seeking approval of the higher capital costs for these repowering projects.

In February 2023, the DOC filed comments recommending approval of recovery of the increased costs of these projects through the RES Rider.

A final decision is pending.

2022 Upper Midwest RFP — In August 2022, NSP-Minnesota launched a RFP for 900 MW of solar or solar-plus-storage hybrid resources to come online by the end of 2025, including up to 300 MW of capacity to reuse the Sherco Unit 2 interconnection rights when the coal facility retires at the end of 2023.

NSP-Minnesota completed its bid evaluation process in December 2022 and will file for approval of the selected projects in early 2023.

2022 Minnesota Electric Vehicle Proposal — In August 2022, NSP-Minnesota filed a request with the MPUC for approval of approximately $320 million of capital investments (2022 through 2026) to support a public charging network, electric school bus pilot, and other expansions and modifications to its residential and commercial electric vehicle programs.

In October 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the proposals.

In February 2023, other parties to the contested proceeding filed their direct testimony ranging in levels of support / opposition to the proposals.

The evidentiary hearing is scheduled in Q2 2023 with a report from the ALJ expected in Q3 2023.

A MPUC decision is expected in late 2023.

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.

Nuclear Power Operations

12 unchanged sentences

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

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

In September 2021, NSP-Minnesota filed an 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.

A decision is expected in late 2023.

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.

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

In February 2023, NSP-Minnesota also filed an application with the NDPSC for an Advance Determination of Prudence for continued operation of the Monticello Plant until at least 2040.

A decision is expected in 2023.

Wholesale and Commodity Marketing Operations

NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products.

NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases.

NSP-Minnesota also engages in trading activity unrelated to these hedging activities.

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

NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.

NSP-Wisconsin

21 unchanged sentences

Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.

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

Power Supply Cost Recovery Factors NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections.

After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.

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

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

NSP-Wisconsin recovers these costs from customers.

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

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 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.

Purchased Power and Transmission Services

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Wholesale and Commodity Marketing Operations

NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates.

NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products.

NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases.

NSP-Minnesota also engages in trading activity unrelated to these hedging activities.

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

NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates.

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

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RTO PSCo is not presently a member of an RTO and does not operate within an RTO energy market.

However, PSCo does make certain sales to other RTO’s, including SPP and participates in a joint dispatch agreement with neighboring utilities.

However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.

DOT Pipeline safety compliance.

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Mechanism Additional Information

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

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.

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The ECA is revised quarterly.

Purchased Capacity Cost Adjustment Recovers purchased capacity payments.

Steam Cost Adjustment Recovers fuel costs to operate the steam system.

The Steam Cost Adjustment rate is revised quarterly.

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

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

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.

Wind Cost Adjustment Recovers costs for customers who choose renewable resources.

Transmission Cost Adjustment Recovers costs for transmission investment between rate cases.

FCA PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC.

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GCA Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.

Pipeline system integrity adjustment Recovers costs for transmission and distribution pipeline integrity management programs (rider ended on Dec.

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

Purchased Capacity Cost Adjustment Recovers purchased capacity payments.

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

Steam Cost Adjustment Recovers fuel costs to operate the steam system.

The Steam Cost Adjustment rate is revised quarterly.

Transmission Cost Adjustment Recovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan.

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

Pending and Recently Concluded Regulatory Proceedings

Colorado Natural Gas Rate Case — In January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million.

The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the pipeline system integrity adjustment rider.

The request was based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a projected rate base of $3.6 billion.

PSCo’s request also included step revenue increases of $40 million (effective Nov.

1, 2023) and $41 million (effective Nov.

1, 2024) related to continued capital investment.

In October 2022, the CPUC approved a rate increase net of rider roll-ins of $64 million.

The decision reflects a stated WACC of 6.7%, a historic test year with a year-end rate base and $16 million of incremental depreciation expense.

PSCo has the option to determine its ROE within a range of 9.2% to 9.5% and its equity ratio within a range of 52% to 55%, as long as it results in a WACC of 6.7%.

The CPUC denied the 2023-2024 step increases.

Base rates were placed in effect November 1, 2022.

Colorado Electric Rate Case — In November 2022, PSCo filed an electric rate case seeking a net increase of $262 million, or 8.2%.

The total request reflects a $312 million increase, which includes $50 million of authorized costs currently recovered through various rider mechanisms.

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

PSCo requested rates effective in September 2023.

A procedural schedule is expected to be established by the CPUC in the first quarter of 2023.

Colorado Resource Plan — In August 2022, the CPUC approved an updated settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030.

The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization.

PSCo filed the recovery method docket in the fourth quarter of 2022.

Key settlement terms include:

• Early retirement of Hayden:

Unit 2 in 2027 (was 2036);

and Unit 1 in 2028 (was 2030).

• Conversion of the Pawnee coal plant to natural gas by no later than Jan.

• Early retirement of Comanche Unit 3 by Jan.

1, 2031 (was 2070) with reduced operations beginning in 2025.

• Addition of ~2,400 MW of wind.

• Addition of ~1,600 MW of universal-scale solar.

• Addition of 400 MW of storage.

• Addition of 1,300 MW of flexible, dispatchable generation.

• Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.

In December 2022, the Company commenced the RFP process for generation resources with a bid receipt date of March 1, 2023.

After reviewing the bids received, PSCo will file a report with the CPUC with recommended resource acquisitions and a CPUC decision on the resources to be acquired is expected in October 2023.

Decoupling Filing — PSCo has a decoupling program, effective April 1, 2020 through Dec.

The program applies to Residential and metered small C&I customers who do not pay a demand charge.

The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate revenue for a specified period.

In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of the 2020 decoupling refunds.

In April 2022, PSCo made its annual filing on this matter.

In December 2022, the ALJ approved a settlement between PSCo, CPUC Staff and the UCA.

The settlement requires PSCo to file a petition for declaratory judgment to address the treatment of any expired balance under the 3% soft cap provisions.

31, 2022, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021 and 2022 results.

Transmission Cost Adjustment — In December 2022, the CPUC suspended PSCo’s request for 2023 TCA rate changes.

The CPUC Staff protested the TCA on the grounds that only projects resulting in new transmission should be included and no repair or replacement of existing infrastructure should be included.

The CPUC consolidated the matter with the pending electric rate case for assessment.

ECA Fuel Recovery — In December 2022, PSCo filed its first quarter 2023 ECA Advice Letter, which sought to recover $123 million of under-recovered 2022 fuel costs over two quarters (instead of the typical one).

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 fuel costs.

Proposed ECA rates were updated to remove the 2022 under-recovered balance and were implemented on Jan.

In February 2023, PSCo submitted an interim ECA filing which included $70 million of the 2022 under-recovered costs.

A filing for the remaining amount is anticipated in the first quarter of 2023.

GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA.

The CPUC has reopened the GCA NOPR and proposed a 2-step process aimed at 1) considering near term process changes to the GCA and 2) a longer term process to evaluate potential performance incentive structures.

In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration.

PSCo worked with other utilities and stakeholders regarding consensus proposed rule amendments for step 2, including a provision that each LDC bring forward its own performance incentive mechanism in a future filing.

In December 2022, the CPUC approved the consensus proposal.

In February 2023, the Governor of Colorado issued an open letter to the CPUC, utilities, and other stakeholders directing agencies to take additional steps to address energy costs.

It is likely this request will result in the opening of additional dockets to further explore the GCA and other related mechanisms.

Additionally, the Colorado Legislature announced the formation of a Joint Select Committee to investigate the source of rising utility rates and explore potential actions to prevent future price instability.

Natural Gas Planning NOPR — In October 2021, the CPUC issued a NOPR to implement recent state legislation requiring natural gas utilities to develop clean heat plans to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria.

Additionally, the proposed rules included new comprehensive natural gas infrastructure planning requirements and related Certificate of Public Convenience and Necessity application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans.

PSCo recommended changes to the proposed rules, which may be incorporated into the final rules issued in the first quarter of 2023.

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

Solar 858 760 1,618

Storage 500 1,348 1,848

Natural Gas 450 219 669

Total 3,133 2,702 5,835

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 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.

Purchased Power and Transmission Service Providers

PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.

Purchased Power — PSCo purchases power from other utilities and IPPs.

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

Purchased Power — PSCo purchases power from other utilities, energy marketers and independent power producers.

Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges.

It also contracts to purchase power for both wind and solar resources.

PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.

Energy Markets — PSCo plans to join the SPP Western Energy Imbalance Service Market in April 2023.

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

Much of PSCo’s long-term purchased power is for wind, solar and storage resources.

PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost.

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.

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The municipalities’ rate setting decisions are subject to PUCT review.

Reviews and approves Integrated Resource Plans for meeting future energy needs

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

Reviews Integrated Resource Plans for meeting future energy needs.

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

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Mechanism Additional Information

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

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

Distribution Cost Recovery Factor Recovers distribution costs not included in rates in Texas.

Electric Vehicle Rider Recovers costs of the Transportation Electrification Plan in New Mexico.

Energy Efficiency Cost Recovery Factor Recovers costs for energy efficiency programs in Texas.

Energy Efficiency Rider Recovers costs for energy efficiency programs in New Mexico.

Fixed Fuel and Purchased Recovery Factor Provides for the over- or under-recovery of energy expenses in Texas.

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

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

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

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.

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

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

Fixed Fuel and Purchased Recovery Factor Provides for the over- or under-recovery of energy expenses in Texas.

Wholesale Fuel and Purchased Energy Cost Adjustment SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC.

Wholesale customers also pay the jurisdictional allocation of production costs.

Electric Vehicle Rider Recovers costs of the Transportation Electrification Plan in New Mexico.

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

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

Pending and Recently Concluded Regulatory Proceedings

2021 Texas Electric Rate Case — In May 2022, the PUCT approved a settlement between SPS and intervening parties.

In July 2022, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $85 million, substantially offset by the recognition of previously deferred costs.

(Millions of Dollars) Year Ended Dec.

Revenue surcharge accrual $ 85

Depreciation and amortization (43)

O&M expenses (16)

Interest expense (12)

Taxes other than income taxes (10)

Fuel and purchased power (2)

2022 New Mexico Electric Rate Case — In November 2022, SPS filed an electric rate case with NMPRC seeking a revenue increase of $78 million, or 10%.

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

Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2032 to 2028.

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

• Staff and intervenor testimony:

March 31, 2023.

• Rebuttal testimony:

April 25, 2023.

• Stipulation:

June 5, 2023.

• End of rate suspension:

2023 Texas Electric Rate Case — On Feb.

8, 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $149 million.

The impact to overall customer bills is expected to be approximately 13%.

The request is based on a historical test year period ended Sept.

30, 2022, with an Update Period ended Dec.

31, 2022, a ROE of 10.65%, an equity ratio of 54.6% and retail rate base of $3.6 billion.

Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2034 to 2028.

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

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

SPS and LP&L Contract Termination — SPS and LP&L have a 25-year, 170 MW partial requirements contract.

In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023).

The settlement agreement requires LP&L to pay SPS $78 million (to the benefit of SPS’ remaining customers).

LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP.

The agreement is pending PUCT and FERC approval.

2022 All-Source RFP — In 2022, SPS issued an RFP, which seeks up to 947 MW of new or existing capacity resources to provide replacement capacity for retiring units and meet SPS’ growing capacity needs through 2027.

SPS will receive bids in the first quarter of 2023 and file for the approval of successful proposals in the second quarter of 2023.

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:

• 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.

• 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.

Purchased Power Arrangements and Transmission Service Providers

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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 scarcity of certain raw materials and interruptions in production and shipping.

These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues.

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.

Electric Distribution and Transmission Transformers

The availability of certain transformers is an industry-wide issue that has been significantly impacted and in some cases may result in delays in projects and new customer connections.

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

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 April 2022, the U.S.

Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential incremental tariffs ranging from 50% to 250%.

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 has been issued and 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 or other restrictions on solar imports (i.e., as a result of implementation of the Uyghur Forced Labor Protection Act) could impact project timelines and costs.

Marshall Wildfire

In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures.

Boulder County authorities are currently inv estigating the fire and have not yet determined a cause.

There were no downed power lines in the ignition area, and nothing the Company has seen to this point indicates that our equipment or operations caused the fire.

In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California.

In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated.

In addition, PSCo has been operating under a commission approved wildfire mitigation plan and carries wildfire liability insurance.

In March 2022, a class action suit was filed in Boulder County pertaining to the Marshall Fire.

In the remote event PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage and have a material adverse effect on our financial condition, results of operations or cash flows.

In December 2022, the District Court judge denied PSCo’s Motion to Dismiss.

MISO Capacity Credits

The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023.

Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing, generating revenues of approximately $90 million in 2022, with approximately $60 million expected in 2023.

These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharing or other mechanisms.

Inflation Reduction Act

In August 2022, the IRA was signed into law.

Key provisions impacting Xcel Energy include:

• Extends current PTC and ITC for renewable technologies (e.g., wind and solar).

• Restores full value of the PTC and ITC for qualifying facilities placed in-service after 2021.

• Creates a PTC for solar, clean hydrogen and nuclear.

• Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.

• Allows companies to monetize or sell credits to unrelated parties.

Xcel Energy anticipates the IRA will materially reduce the cost of renewable energy, resulting in significant customer savings.

The IRA is expected to allow Xcel Energy to monetize tax credits more efficiently with the incremental benefits passed through to customers.

Transferability provisions apply to eligible tax credits generated starting in 2023 for both new and existing facilities.

Xcel Energy anticipates tax credit transferability from existing renewable projects will improve cash from operations by $1.8 billion (2023 - 2027), assuming constructive regulatory outcomes and the development of a market.

The IRA creates a nuclear PTC beginning in 2024 that may also provide additional customer savings.

The annual customer benefit from these PTCs could range from $0 to $300 million, depending on locational marginal pricing, as well as constructive U.S.

Treasury guidance regarding computation of the credits.

In addition, the IRA created a new corporate AMT.

Xcel Energy does not anticipate AMT having a material cash impact based on current estimates and our interpretation of its application.

Winter Storm Uri

In February 2021, the United States experienced Winter Storm Uri.

Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation.

The cold weather also affected the country’s supply and demand for natural gas.

These factors contributed to extremely high market prices for natural gas and electricity.

As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $1 billion (largely deferred as regulatory assets).

Xcel Energy has received recovery approval from all of our impacted states except for Texas, which is pending.

A summary of pending and recently approved regulatory requests for Winter Storm Uri cost recovery is listed below.

Utility Subsidiary Jurisdiction Regulatory Status

NSP-Minnesota Minnesota In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021, pending a prudency review.

The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period.

In August 2022, the MPUC approved recovery of Uri storm costs with a $19 million disallowance.

PSCo Colorado In May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge.

In July 2022, the CPUC approved a partial settlement providing full recovery of fuel costs, with the exception of an $8 million disallowance, over 24 months for electric and 30 months for natural gas customers.

SPS Texas In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million.

In April 2022, interim rates designed to recover $121 million over 30 months were approved, subject to PUCT approval through the triennial Fuel Reconciliation proceeding.

In July 2022, the intervenors filed recommendations.

The Texas Industrial Energy Consumers and PUCT staff recommended disallowances of approximately $10 million (off-system sales margins).

The Office of Public Utility Counsel recommended disallowances of approximately $15 million (off-system sales margins and adjustment to energy loss factors).

The Alliance of Xcel Municipalities recommended disallowances of approximately $100 million (natural gas storage, contracted capability and off-system sales margins).

In November 2022, the ALJs found that costs were prudently incurred and recommended no disallowances.

A final PUCT decision is anticipated in the first quarter of 2023.

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.

Critical Accounting Policies and Estimates

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The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.

Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized based on an evaluation of expected future taxable income.

Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized.

Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized.

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Pension assumptions are continually reviewed.

31, 2022, Xcel Energy set the rate of return on assets used to measure pension costs at 6.93%, which is 44 basis points higher than the rate set in 2021.

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.

The rate of return used to measure postretirement health care costs is 5.00% at Dec.

31, 2022, which is 90 basis points higher than the rate set in 2021.

Xcel Energy’s pension investment strategy is based on plan-specific investments that seek to minimize investment and interest rate risk as a plan’s funded status increases over time.

This strategy 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 5.80% at Dec.

This represents a 272 basis point and 271 basis point increase, respectively, from 2021.

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

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

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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 2022 were $50 million and will remain relatively consistent in future years.

Investment returns were less than the assumed levels in 2022, but exceeded the assumed levels in 2021 and 2020.

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.

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

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As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 13 years in 2023).

Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $66 million in 2023 and $58 million in 2024, while the actual pension costs were $114 million in 2022 and $121 million in 2021.

The expected decrease in 2023 is primarily due to the reductions in loss amortizations.

Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $59 million in 2024 and $61 million in 2025, while the actual pension costs were $74 million in 2023 and $114 in 2022.

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

Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2021 - 2024:

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

• Regulatory Commissions in Colorado, 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.

• 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.

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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.

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.

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.

Derivatives, Risk Management and Market Risk

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Market price movements can exceed 10% under abnormal circumstances.

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.

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

VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.

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2023 $ — $ — $ 1 $ —

2021 $ 1 $ 2 $ 52 $ 1

A short-term increase in VaR occurred during the week of Feb.

12, 2021 through Feb.

17, 2021, the portfolio VaR reached a high of $52 million.

This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri.

Prior to this weather event, VaR was $1 million and returned to $1 million by Feb.

Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2023 and 2024 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe, and the United States.

Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2024 through 2027 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.

We are closely monitoring the evolving situation in Ukraine and its global impacts.

NSP-Minnesota is in the process of entering into new contracts to reduce the risk of supply interruptions of nuclear material from Russia.

NSP-Minnesota will take additional further action to reduce this risk as necessary.

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.

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

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

The increase was primarily due to the deferral of net natural gas, fuel and purchased energy costs incurred during Winter Storm Uri in the first quarter of 2021.

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.

Investing Cash Flows

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Components of change — 2023 vs.

Lower debt issuances (1,159)

Higher repayments of long-term debt (184)

Higher debt issuances, net of repayments 80

Lower proceeds from issuance of common stock (52)

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

The decrease was primarily related to the amount/timing of debt issuances and repayments associated with Winter Storm Uri.

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

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

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Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.

Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, as well as inflation.

Recovery of the effects of inflation through higher customer rates is dependent upon receiving adequate and timely rate increases.

Rate increases may not be retroactive and often lag increases in costs caused by inflation.

On occasion, Xcel Energy may enter into rate settlement agreements, which require us to wait for a period of time to file the next base rate increase request.

These agreements may result in regulatory lag whereby the impact of inflation may not yet be reflected in rates, or a delay may occur between capital project completion and the start of rate recovery.

Xcel Energy attempts to mitigate the potential impact of inflation through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances.

Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation.

Material Cash Requirements and Other Commitments

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1,520 277 509 313 421

Unconditional purchase obligations (b)

Unconditional purchase obligations (b) (c)

4,022 1,429 1,267 686 640

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

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

57 18 27 12 —

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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.

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

Capital Expenditures — Base capital expenditures and incremental capital forecasts:

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By Function 2023 2024 2025 2026 2027 2028 2024 - 2028 Total

Electric distribution $ 1,370 $ 1,610 $ 1,790 $ 1,680 $ 2,000 $ 2,450 $ 9,530

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

Electric distribution 1,730 1,770 1,960 2,200 2,200 2,470 10,600

Renewables 350 1,500 2,910 940 240 20 5,610

Electric generation 780 940 1,290 1,050 1,060 600 4,940

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Other 1,250 760 420 670 630 630 3,110

Renewables 410 280 280 470 — — 1,030

Total base capital expenditures $ 6,210 $ 7,420 $ 9,280 $ 7,940 $ 7,600 $ 6,760 $ 39,000

The base five-year capital forecast includes transmission expansion through the proposed Colorado Pathway (approximately $1.7 billion) and MISO Tranche 1 (approximately $1.2 billion) as well as the proposed 460 MW Sherco Solar Generating Unit 1 and 2 (approximately $600 million).

The base capital investment plan does not include any potential renewable generation assets approved in our Minnesota and Colorado resource plans or additional transmission capital needed to integrate new renewable generation additions in Colorado, beyond the Pathway project.

We expect further clarification in the second half of 2023 after the commissions rule on the recommended resource plan portfolios, which could result in incremental capital expenditures of approximately $2 to $4 billion (assuming 50% ownership of the renewable projects).

Furthermore, the base capital investment plan does not include any potential generation assets associated with our 2022 SPS Request for Proposal, which seeks up to 947 MW of new or existing capacity resources.

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.

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.

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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.

Current estimated financing plans of Xcel Energy for 2023 through 2027:

Current estimated financing plans of Xcel Energy for 2024 through 2028 (includes the impact of tax credit transferability):

(Millions of Dollars)

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Xcel Energy Inc.

and its utility subsidiaries have registration statements on file with the SEC pursuant to which they may sell securities from time to time.

These registration statements, which are uncapped, permit Xcel Energy Inc.

and its utility subsidiaries to issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings, and in the case of our utility subsidiaries, subject to commission approval.

and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc.

and its utility subsidiaries to issue debt, equity and other securities.

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

Planned Financing Activity — Xcel Energy’s 2024 financing plans reflect the following:

(Millions of Dollars) Security Amount Anticipated Timing

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

Xcel Energy Inc.

Senior Unsecured Bonds $ 500 Third Quarter

PSCo First Mortgage Bonds 700 Second Quarter

SPS First Mortgage Bonds 100 Third Quarter

NSP-Minnesota First Mortgage Bonds 750 Second Quarter

NSP-Wisconsin First Mortgage Bonds 125 Second Quarter

Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy also plans to issue approximately $85 million of equity annually through the DRIP and benefit programs during the five-year forecast time period.

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.

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

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

Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023 GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per share.

Key assumptions as compared with 2022 levels unless noted:

• Constructive outcomes in all rate case and regulatory proceedings.

• Normal weather patterns for the year.

• Weather-normalized retail electric sales are projected to increase ~1%.

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

Xcel Energy 2024 Earnings Guidance — Xcel Energy’s 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.

Key assumptions as compared with 2023 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.

• Capital rider revenue is projected to increase $70 million to $80 million (net of PTCs).

• O&M expenses are projected to decline ~2%.

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

• Depreciation expense is projected to increase approximately $250 million to $260 million.

• Property taxes are projected to increase approximately $35 million to $45 million.

• Interest expense (net of AFUDC - debt) is projected to increase $100 million to $110 million.

• Property taxes are projected to increase $50 million to $60 million.

• Interest expense (net of AFUDC - debt) is projected to increase $130 million to $140 million, net of interest income.

• AFUDC - equity is projected to increase $45 million to $55 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.

Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments.

Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.

As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.

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

• Deliver long-term annual EPS growth of 5% to 7% based off of a 2022 base of $3.15 per share, which represents the mid-point of the original 2022 guidance range of $3.10 to $3.20 per share.

• 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 annual dividend increases of 5% to 7%.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis