--- ticker: XEL company: Xcel Energy Inc. filing_type: 10-K year_current: 2024 year_prior: 2023 risks_added: 14 risks_removed: 15 risks_modified: 64 risks_unchanged: 48 source: SEC EDGAR url: https://riskdiff.com/xel/2024-vs-2023/ markdown_url: https://riskdiff.com/xel/2024-vs-2023/index.md generated: 2026-06-01 --- # Xcel Energy Inc.: 10-K Risk Factor Changes 2024 vs 2023 > Source: U.S. Securities and Exchange Commission (EDGAR) > Generated: 2026-06-01 > All data extracted directly from official filings. No hallucinated content. ## Summary | Status | Count | |--------|-------| | New risks added | 14 | | Risks removed | 15 | | Risks modified | 64 | | Unchanged | 48 | --- ## New in Current Filing: Increased risks of regulatory penalties could negatively impact our business. The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties. In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. --- ## New in Current Filing: We are subject to environmental laws and regulations, with which compliance could be difficult and costly. We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations. --- ## New in Current Filing: 2022 Comparison with 2021 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2021 to Dec. 31, 2022 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2022, which was filed with the SEC on Feb. 23, 2023. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. --- ## New in Current Filing: Additional Information Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers 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 RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. (a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 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. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In October 2023, the MPUC denied NSP-Minnesota's request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023.2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota's request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).Next steps in the procedural schedule are expected to be as follows:•Intervenor direct testimony: April 19, 2024•Rebuttal testimony: May 24, 2024•Evidentiary hearings: July 10-12, 2024•ALJ Report: October 28, 2024•MPUC Order Due: March 14, 2025 --- ## New in Current Filing: 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. 31 31 31 Table of Contents Table of Contents 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. 1, 2024.NSP SystemPending and Recently Concluded Regulatory Proceedings2022 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 ServicesThe NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.Wholesale and Commodity Marketing OperationsNSP-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. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance. 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. 1, 2024.NSP SystemPending and Recently Concluded Regulatory Proceedings2022 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 ServicesThe NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. 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. 1, 2024. NSP System --- ## New in Current Filing: Pending and Recently Concluded Regulatory Proceedings 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. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In October 2023, the MPUC denied NSP-Minnesota's request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023. 2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota's request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024). Next steps in the procedural schedule are expected to be as follows: •Intervenor direct testimony: April 19, 2024 •Rebuttal testimony: May 24, 2024 •Evidentiary hearings: July 10-12, 2024 •ALJ Report: October 28, 2024 •MPUC Order Due: March 14, 2025 30 30 30 Table of Contents Table of Contents 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin's natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-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 AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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.Recently Concluded Regulatory ProceedingsWisconsin 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. 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.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. 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. --- ## New in Current Filing: Additional Information Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers 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 RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. (a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 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. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In October 2023, the MPUC denied NSP-Minnesota's request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023.2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota's request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).Next steps in the procedural schedule are expected to be as follows:•Intervenor direct testimony: April 19, 2024•Rebuttal testimony: May 24, 2024•Evidentiary hearings: July 10-12, 2024•ALJ Report: October 28, 2024•MPUC Order Due: March 14, 2025 --- ## New in Current Filing: Supply Chain Xcel Energy's ability to meet customer energy requirements, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. Inflationary pressures, labor shortages, and the impact of geopolitical events have further exacerbated these disruptions. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work. Additionally, certain products, components, and equipment, particularly in renewables categories, originate in countries that could face tariffs, fines, or restrictions from government or other regulatory bodies and present a cost and supply risk until there is sufficient capacity and supply base with adequate capacity to meet US needs. Electric Meters and Transformers Supply chain issues associated with semiconductors delayed the availability of AMI meters, which led to a reduced number of meters deployed in 2022. Xcel Energy saw significant improvement in meter availability in 2023 and we expect normal conditions in 2024 and going forward. Xcel Energy expects to complete AMI meter deployment in 2025. Additionally, the availability of certain transformers is an industry-wide issue that has significantly impacted and in some cases resulted in delays to projects and new customer connections. Proposed governmental actions related to transformer efficiency standards may compound these delays in the future. Xcel Energy continues to seek alternative suppliers and prioritize work plans to mitigate the impacts of supply constraints. Solar Resources In August 2023, the U.S. Department of Commerce completed its anti-circumvention investigation. It concluded that CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia would be subject to incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports. 35 35 35 Table of Contents Table of Contents 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, the 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 GrantIn 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) GrantIn 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 EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 2023 and 2022, Xcel Energy had regulatory assets of $3.4 billion and $3.9 billion, respectively and regulatory liabilities of $6.4 billion and $6.0 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2023, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information. 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, the 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 GrantIn 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) GrantIn 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. 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 in Current Filing: Critical Accounting Policies and Estimates Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis. --- ## New in Current Filing: 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. --- ## New in Current Filing: Derivatives, Risk Management and Market Risk We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans. Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2023:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$1 $(3)$(3)$ - $(5)NSP-Minnesota (b)(1)(8)(6)(1)(16)PSCo (a) - 1 2 - 3 PSCo (b)(10)6 2 - (2)$(10)$(4)$(5)$(1)$(20)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $ - $9 $8 $17 PSCo (b)4 - - - 4 $4 $ - $9 $8 $21 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20232022Fair value of commodity trading net contracts outstanding at Jan. 1$(10)$(33)Contracts realized or settled during the period(2)(15)Commodity trading contract additions and changes during the period13 38 Fair value of commodity trading net contracts outstanding at Dec. 31$1 $(10)A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $4 million at Dec. 31, 2023 and $8 million at Dec. 31, 2022. Market price movements can exceed 10% under abnormal circumstances.Xcel Energy's' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2023$ - $ - $1 $ - 20222 1 5 - Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2023: Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$1 $(3)$(3)$ - $(5)NSP-Minnesota (b)(1)(8)(6)(1)(16)PSCo (a) - 1 2 - 3 PSCo (b)(10)6 2 - (2)$(10)$(4)$(5)$(1)$(20) NSP-Minnesota (a) NSP-Minnesota (b) PSCo (a) PSCo (b) Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $ - $9 $8 $17 PSCo (b)4 - - - 4 $4 $ - $9 $8 $21 NSP-Minnesota (b) PSCo (b) (a)Prices actively quoted or based on actively quoted prices. (b)Prices based on models and other valuation methods. Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31: (Millions of Dollars)20232022Fair value of commodity trading net contracts outstanding at Jan. 1$(10)$(33)Contracts realized or settled during the period(2)(15)Commodity trading contract additions and changes during the period13 38 Fair value of commodity trading net contracts outstanding at Dec. 31$1 $(10) A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $4 million at Dec. 31, 2023 and $8 million at Dec. 31, 2022. Market price movements can exceed 10% under abnormal circumstances. Xcel Energy's' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows: --- ## New in Current Filing: Recently Issued Segment Reporting - In November 2023, the FASB issued ASU 2023-07 - Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. Income Taxes - In December 2023, the FASB issued ASU 2023-09 - Income Taxes (Topic 740) - Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the effective tax rate reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. Income Taxes - In December 2023, the FASB issued ASU 2023-09 - Income Taxes (Topic 740) - Improvements to Income Tax Disclosures --- ## New in Current Filing: Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2023Common Stock Outstanding (Shares) as of Dec. 31, 20221,000,000,000 $2.50 554,941,703 549,578,018 Dividend and Other Capital-Related Restrictions - Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.'s utility subsidiaries' dividends are subject to the FERC's jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2023: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2023NSP-Minnesota47.2 %57.6 %52.3 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.6 NSP-Wisconsin (a) SPS (b) (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. (b) Excludes short-term debt. Excludes short-term debt. (Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,508 $15,702 $16,140 NSP-Wisconsin9 2,520 N/ASPS (a)617 7,298 N/A SPS (a) (a)May not pay a dividend that would cause a loss of its investment grade bond rating. (a) Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. Amounts authorized to issue as of Dec. 31, 2023:(Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota52.8% of total capitalization(a)$2,400 (a)NSP-Wisconsin$625 150 PSCo450 800 SPS100 600 (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. 6. RevenuesRevenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy's operating revenues consisted of the following: Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 - 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 - - 815 Transmission649 - - 649 Other63 156 - 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 - 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 - - 1,354 Transmission675 - - 675 Other97 178 - 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310 Amounts authorized to issue as of Dec. 31, 2023: (Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota52.8% of total capitalization(a)$2,400 (a)NSP-Wisconsin$625 150 PSCo450 800 SPS100 600 (a) (a) (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. (a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. --- ## New in Current Filing: 6. Revenues Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy's operating revenues consisted of the following: Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 - 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 - - 815 Transmission649 - - 649 Other63 156 - 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 - 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 - - 1,354 Transmission675 - - 675 Other97 178 - 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310 --- ## No Match in Current: Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather. *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows. --- ## No Match in Current: We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly. *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency's Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows. --- ## No Match in Current: Public Utility Regulation *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas. Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality. See Rate Matters within Note 12 to the consolidated financial statements for further information. --- ## No Match in Current: Additional Information *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. 29 29 29 Table of Contents Table of Contents Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs in Minnesota.Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.RESRecovers cost of renewable generation in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Infrastructure RiderRecovers costs for investments in generation in South Dakota.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Purchased Gas AdjustmentProvides 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.GUIC RiderRecovers 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. The statute authorizing the GUIC Rider is set to expire June 30, 2023.Sales True-upNSP-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.(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 Minnesota Electric Rate Case - In 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.In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/AIn 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows:•ALJ Report: March 31, 2023.•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. 1, 2022.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. 1, 2021. 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. 1, 2022.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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs in Minnesota.Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.RESRecovers cost of renewable generation in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Infrastructure RiderRecovers costs for investments in generation in South Dakota.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Purchased Gas AdjustmentProvides 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.GUIC RiderRecovers 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. The statute authorizing the GUIC Rider is set to expire June 30, 2023.Sales True-upNSP-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.(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 Minnesota Electric Rate Case - In 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.In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/A --- ## No Match in Current: Additional Information on Regulatory Authority *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. 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. Pipeline safety compliance. --- ## No Match in Current: Additional Information *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. 29 29 29 Table of Contents Table of Contents Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs in Minnesota.Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.RESRecovers cost of renewable generation in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Infrastructure RiderRecovers costs for investments in generation in South Dakota.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Purchased Gas AdjustmentProvides 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.GUIC RiderRecovers 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. The statute authorizing the GUIC Rider is set to expire June 30, 2023.Sales True-upNSP-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.(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 Minnesota Electric Rate Case - In 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.In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/AIn 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows:•ALJ Report: March 31, 2023.•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. 1, 2022.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. 1, 2021. 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. 1, 2022.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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs in Minnesota.Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.RESRecovers cost of renewable generation in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Infrastructure RiderRecovers costs for investments in generation in South Dakota.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Purchased Gas AdjustmentProvides 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.GUIC RiderRecovers 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. The statute authorizing the GUIC Rider is set to expire June 30, 2023.Sales True-upNSP-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.(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 Minnesota Electric Rate Case - In 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.In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/A --- ## No Match in Current: Supply Chain *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* 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. 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. --- ## No Match in Current: Electric Distribution and Transmission Transformers *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* 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. --- ## No Match in Current: Solar Resources *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* 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%. 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. --- ## No Match in Current: Marshall Wildfire *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* 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 investigating 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. 35 35 35 Table of Contents Table of Contents 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 CreditsThe 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 ActIn 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 UriIn 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 SubsidiaryJurisdictionRegulatory StatusNSP-MinnesotaMinnesotaIn 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.PSCoColoradoIn 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. SPSTexasIn 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.Critical Accounting Policies and EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. 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 CreditsThe 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 ActIn 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. 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. --- ## No Match in Current: MISO Capacity Credits *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* 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. --- ## No Match in Current: Inflation Reduction Act *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* 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 UriIn 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 SubsidiaryJurisdictionRegulatory StatusNSP-MinnesotaMinnesotaIn 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.PSCoColoradoIn 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. SPSTexasIn 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.Critical Accounting Policies and EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. --- ## No Match in Current: Winter Storm Uri *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* 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 SubsidiaryJurisdictionRegulatory StatusNSP-MinnesotaMinnesotaIn 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.PSCoColoradoIn 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. SPSTexasIn 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. 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. 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. --- ## No Match in Current: Major classes of property, plant and equipment *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* (Millions of Dollars)Dec. 31, 2022Dec. 31, 2021Property, plant and equipment, netElectric plant$49,639 $48,680 Natural gas plant8,514 7,758 Common and other property2,970 2,602 Plant to be retired (a)2,217 1,200 CWIP2,124 1,969 Total property, plant and equipment65,464 62,209 Less accumulated depreciation(17,502)(17,060)Nuclear fuel3,183 3,081 Less accumulated amortization(2,892)(2,773)Property, plant and equipment, net$48,253 $45,457 Plant to be retired (a) (a)Amounts as of Dec. 31, 2021 include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 1 and 2 and Craig Units 1 and 2 for PSCo; and Tolk and coal generation assets at Harrington pending facility gas conversion for SPS. Following the June 2022 approval of PSCo's revised resource plan settlement, amounts as of Dec. 31, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion as well as the removal of Comanche Unit 1 that was retired in 2022. Amounts are presented net of accumulated depreciation. --- ## No Match in Current: Dec. 31, 2021 (a) *This section from the 2023 filing does not have a high-confidence textual match in 2024. It may have been removed, merged, or substantially reworded.* Net AROs (b) One to five years One five Excess deferred taxes - TCJA One to 12 years One Six years Six 12 years Conservation programs (c) One to two years One two Contract valuation adjustments (d) One to two years One two One to two years One two One to two years One two Less than one year one One to two years One two (a)Prior period amounts have been restated to conform with current year presentation. (b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (c)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. 57 57 57 Table of Contents Table of Contents Components of regulatory liabilities: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2022Dec. 31, 2021 (a)Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentDeferred income tax adjustments and TCJA refunds (b)7Various$9 $3,110 $26 $3,230 Plant removal costs1, 12Various - 1,819 - 1,655 Effects of regulation on employee benefit costs (c)Various - 247 - 235 Renewable resources and environmental initiativesVarious6 173 1 101 Revenue decouplingOne to two years - 77 9 41 ITC deferrals1Various1 61 - 53 Formula ratesOne to two years32 17 19 11 Contract valuation adjustments (d)1, 10One to two years175 1 56 1 Deferred natural gas, electric, steam energy/fuel costsLess than one year39 - 50 - Conservation programs (e)1Less than one year72 - 42 - DOE settlementVarious12 3 14 14 OtherVarious72 61 54 64 Total regulatory liabilities (f)$418 $5,569 $271 $5,405 --- ## Modified: Wholesale and Commodity Marketing Operations **Key changes:** - Reworded sentence: "NMPRCRetail electric operations, retail rates and services and the construction of transmission or generation.Reviews Integrated Resource Plans for meeting future energy needs.FERCWholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.SPP RTO and SPP Integrated and Wholesale MarketsSPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets." - Reworded sentence: "DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAdvanced Metering System SurchargeRecovers costs incurred in deployment of the Advanced Metering System in Texas.Consulting Fee RiderRecovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT.Distribution Cost Recovery FactorRecovers distribution costs not included in rates in Texas.Electric Vehicle RiderRecovers costs of the Transportation Electrification Plan in New Mexico.Energy Efficiency Cost Recovery FactorRecovers costs for energy efficiency programs in Texas.Energy Efficiency RiderRecovers costs for energy efficiency programs in New Mexico.Fixed Fuel and Purchased Recovery FactorProvides for the over- or under-recovery of energy expenses in Texas." **Prior (2023):** 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. **Current (2024):** NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCo --- ## Modified: Short-Term Borrowings **Key changes:** - Reworded sentence: "31, 2023Year Ended Dec." - Reworded sentence: "31, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement." - Reworded sentence: "31, 2023 and 2022, there were $44 million and $43 million of letters of credit outstanding under the credit facilities, respectively." - Reworded sentence: "Terms of Credit Agreements - In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks." - Reworded sentence: "31, 2023, Xcel Energy Inc." **Prior (2023):** Short-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements. Commercial paper and other borrowings outstanding: (Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2022Year Ended Dec. 31202220212020Borrowing limit$3,550 $3,550 $3,100 $3,100 Amount outstanding at period end813 813 1,005 584 Average amount outstanding416 552 1,399 1,126 Maximum amount outstanding813 1,357 2,054 2,080 Weighted average interest rate, computed on a daily basis4.20 %1.47 %0.57 %1.45 %Weighted average interest rate at period end4.66 4.66 0.31 0.23 Bilateral Credit Agreement - In April 2022, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. As of Dec. 31, 2022, NSP-Minnesota had $54 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2022 and 2021, there were $43 million and $19 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value. Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Amended Credit Agreements - In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit was increased to $3.55 billion. The amended credit agreements have substantially the same terms and conditions as the prior agreements, with the following changes:•Maturities extended from June 2024 to September 2027.•Borrowing limit for Xcel Energy Inc. increased from $1.25 billion to $1.5 billion.•Borrowing limit for NSP-Minnesota increased from $500 million to $700 million. Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Amended Credit Agreements - In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit was increased to $3.55 billion. The amended credit agreements have substantially the same terms and conditions as the prior agreements, with the following changes: •Maturities extended from June 2024 to September 2027. •Borrowing limit for Xcel Energy Inc. increased from $1.25 billion to $1.5 billion. •Borrowing limit for NSP-Minnesota increased from $500 million to $700 million. 58 58 58 Table of Contents Table of Contents Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars)Additional Periods for Which a One-Year Extension May Be Requested (b)20222021Xcel Energy Inc. (c)60 %60 %$350 2 NSP-Minnesota48 47 150 2 NSP-Wisconsin47 49 N/A1 SPS46 47 50 2 PSCo44 44 100 2 (a) Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b) All extension requests are subject to majority bank group approval. (c) The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2022, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2022:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $231 $1,269 PSCo700 321 379 NSP-Minnesota700 222 478 SPS500 36 464 NSP-Wisconsin150 47 103 Total$3,550 $857 $2,693 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2022 and 2021.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars):Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20222021Unsecured senior notes0.50 Oct. 15, 2023500 500 Unsecured senior notes3.30 June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes (a)1.75 March 15,2027500 500 Unsecured senior notes 4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes 2.60 Dec. 1, 2029500 500 Unsecured senior notes3.40 June 1, 2030600 600 Unsecured senior notes (a)2.35 Nov. 15, 2031300 300 Unsecured senior notes (b)4.60 June 1, 2032700 - Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sep. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(7)(8)Unamortized debt issuance cost(35)(33)Current maturities (500) - Total long-term debt$5,338 $5,139 (a)2021 financing.(b)2022 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20222021First mortgage bonds2.15 %Aug. 15, 2022$ - $300 First mortgage bonds2.60 May 15, 2023400 400 First mortgage bonds7.125 July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds (a)2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sep. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds (a)3.20 April 1,2052425 425 First mortgage bonds (b)4.50 June 1, 2052500 - Other long-term debt3 3 Unamortized discount(45)(44)Unamortized debt issuance cost(66)(62)Current maturities(400)(300)Total long-term debt$6,542 $6,447 (a)2021 financing.(b)2022 financing. Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars)Additional Periods for Which a One-Year Extension May Be Requested (b)20222021Xcel Energy Inc. (c)60 %60 %$350 2 NSP-Minnesota48 47 150 2 NSP-Wisconsin47 49 N/A1 SPS46 47 50 2 PSCo44 44 100 2 (a) Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b) All extension requests are subject to majority bank group approval. (c) The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2022, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2022:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $231 $1,269 PSCo700 321 379 NSP-Minnesota700 222 478 SPS500 36 464 NSP-Wisconsin150 47 103 Total$3,550 $857 $2,693 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2022 and 2021.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Features of the credit facilities: Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars)Additional Periods for Which a One-Year Extension May Be Requested (b)20222021Xcel Energy Inc. (c)60 %60 %$350 2 NSP-Minnesota48 47 150 2 NSP-Wisconsin47 49 N/A1 SPS46 47 50 2 PSCo44 44 100 2 **Current (2024):** Short-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements. Commercial paper and other borrowings outstanding: (Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2023Year Ended Dec. 31202320222021Borrowing limit$3,550 $3,550 $3,550 $3,100 Amount outstanding at period end785 785 813 1,005 Average amount outstanding339 491 552 1,399 Maximum amount outstanding785 1,241 1,357 2,054 Weighted average interest rate, computed on a daily basis5.51 %5.12 %1.47 %0.57 %Weighted average interest rate at period end5.52 5.52 4.66 0.31 Bilateral Credit Agreement - In April 2023, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2023 and 2022, there were $44 million and $43 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Terms of Credit Agreements - In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. Bilateral Credit Agreement - In April 2023, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. As of Dec. 31, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2023 and 2022, there were $44 million and $43 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value. Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Terms of Credit Agreements - In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. 58 58 58 Table of Contents Table of Contents Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20232022Xcel Energy Inc. (d)59.8 %59.7 %$350 2 NSP-Minnesota47.7 47.7 150 2 NSP-Wisconsin48.2 47.4 N/A1 SPS46.1 45.7 50 2 PSCo44.8 44.0 100 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2023, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2023:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $165 $1,335 PSCo700 349 351 NSP-Minnesota700 180 520 SPS500 75 425 NSP-Wisconsin150 60 90 Total$3,550 $829 $2,721 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2023 and 2022.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars):Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20232022Unsecured senior notes0.50 %Oct. 15, 2023$ - $500 Unsecured senior notes3.30 June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes1.75 March 15, 2027500 500 Unsecured senior notes4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes2.60 Dec. 1, 2029500 500 Unsecured senior notes 3.40 June 1, 2030600 600 Unsecured senior notes 2.35 Nov. 15, 2031300 300 Unsecured senior notes (a)4.60 June 1, 2032700 700 Unsecured senior notes (b)5.45 Aug. 15, 2033800 - Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sept. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(8)(7)Unamortized debt issuance cost(36)(35)Current maturities - (500)Total long-term debt$6,136 $5,338 (a)2022 financing.(b)2023 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds2.60 %May 15, 2023$ - $400 First mortgage bonds7.125 July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds 6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sept. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds3.20 April 1, 2052425 425 First mortgage bonds (a)4.50 June 1, 2052500 500 First mortgage bonds (b)5.10 May 15, 2053800 - Other long-term debt2 3 Unamortized discount(49)(45)Unamortized debt issuance cost(73)(66)Current maturities - (400)Total long-term debt$7,330 $6,542 (a)2022 financing.(b)2023 financing. Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20232022Xcel Energy Inc. (d)59.8 %59.7 %$350 2 NSP-Minnesota47.7 47.7 150 2 NSP-Wisconsin48.2 47.4 N/A1 SPS46.1 45.7 50 2 PSCo44.8 44.0 100 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2023, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2023:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $165 $1,335 PSCo700 349 351 NSP-Minnesota700 180 520 SPS500 75 425 NSP-Wisconsin150 60 90 Total$3,550 $829 $2,721 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2023 and 2022.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Features of the credit facilities: Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20232022Xcel Energy Inc. (d)59.8 %59.7 %$350 2 NSP-Minnesota47.7 47.7 150 2 NSP-Wisconsin48.2 47.4 N/A1 SPS46.1 45.7 50 2 PSCo44.8 44.0 100 2 --- ## Modified: Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin **Key changes:** - Reworded sentence: "(Millions of Dollars)20232022Natural gas revenues$2,645 $3,080 Cost of natural gas sold and transported(1,456)(1,910)Natural gas margin$1,189 $1,170" **Prior (2023):** (Millions of Dollars)20222021Natural gas revenues$3,080 $2,132 Cost of natural gas sold and transported(1,910)(1,081)Natural gas margin$1,170 $1,051 **Current (2024):** (Millions of Dollars)20232022Natural gas revenues$2,645 $3,080 Cost of natural gas sold and transported(1,456)(1,910)Natural gas margin$1,189 $1,170 --- ## Modified: Station, Location and Unit at Dec. 31, 2023 **Key changes:** - Reworded sentence: "MW (a) (b) (b) (c) (c) (a)Summer 2023 net dependable capacity." - Reworded sentence: "31, 2023: Conductor MilesNSP-MinnesotaNSP-WisconsinPSCoSPSTransmission500 KV2,916 - - - 345 KV12,845 3,019 5,421 11,701 230 KV2,300 - 12,244 9,854 161 KV626 1,818 - - 138 KV - - 92 - 115 KV8,071 1,862 4,994 14,896 Less than 115 KV6,640 5,467 1,782 4,494 Total Transmission33,398 12,166 24,533 40,945 DistributionLess than 115 KV83,854 27,971 80,176 23,965 Total117,252 40,137 104,709 64,910 Electric utility transmission and distribution substations at Dec." - Reworded sentence: "31, 2018 in stock or index - including reinvestment of dividends." **Prior (2023):** MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) Nobles-Nobles County, MN, 133 Units (e) (d) (d) (d) (a)Summer 2022 net dependable capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)Refuse-derived fuel is made from municipal solid waste. (d)Capacity is attainable only when wind conditions are sufficiently available. (e)Repowered in 2022. NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 (a)Summer 2022 net dependable capacity.(b)Refuse-derived fuel is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975335 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 Manchief, CO, 2 Units (e)Natural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 Various locations, 8 UnitsNatural GasVarious251 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Total6,151 (a)Summer 2022 net dependable capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Purchased in 2022. (f)Capacity is attainable only when wind conditions are sufficiently available. NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 **Current (2024):** MW (a) (b) (c) (d) (e) (e) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (f) (e) (e) (e) (e) (e) Northern Wind-Murray County, MN, 37 Units (g) (e) (e) (e) (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023. (c)Based on NSP-Minnesota's ownership of 59%. (d)RDF is made from municipal solid waste. (e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota's wind facilities had a weighted-average capacity factors of 43%. (f)Repowered in 2023. (g)Purchased in 2023. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo's wind facilities had a weighted-average capacity factors of 43%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 --- ## Modified: We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly. **Key changes:** - Reworded sentence: "Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future." - Reworded sentence: "Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards." - Reworded sentence: "Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets." - Added sentence: "We may be subject to climate change lawsuits." - Added sentence: "An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages." **Prior (2023):** We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. 22 22 22 Table of Contents Table of Contents Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B - UNRESOLVED STAFF COMMENTSNone. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations. **Current (2024):** Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency's Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. 21 21 21 Table of Contents Table of Contents We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B - UNRESOLVED STAFF COMMENTSNone. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows. --- ## Modified: Comparison of Five Year Cumulative Total Return* **Key changes:** - Reworded sentence: "31, 2018 in stock or index - including reinvestment of dividends." - Reworded sentence: "31, 2023, no equity securities that are registered by Xcel Energy Inc." - Reworded sentence: "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." - Added sentence: "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." - Reworded sentence: "These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP." **Prior (2023):** * $100 invested on Dec. 31, 2017 in stock or index - including reinvestment of dividends. Fiscal years ended Dec. 31. 25 25 25 Table of Contents Table of Contents Purchases of Equity Securities by Issuer and Affiliated PurchasersFor the quarter ended Dec. 31, 2022, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers. ITEM 6 - [RESERVED]ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSNon-GAAP Financial MeasuresThe 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. Xcel Energy's management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors' understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies' similarly titled non-GAAP financial measures.Ongoing ROEOngoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity's average stockholder's equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.'s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy's core earnings and underlying performance. 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. Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:20222021Diluted Earnings (Loss) Per ShareGAAP and Ongoing Diluted EPSGAAP and Ongoing Diluted EPSPSCo$1.33 $1.22 NSP-Minnesota1.23 1.12 SPS0.64 0.59 NSP-Wisconsin0.23 0.20 Earnings from equity method investments - WYCO0.04 0.05 Regulated utility (a)3.47 3.18 Xcel Energy Inc. and Other(0.29)(0.22)Total (a)$3.17 $2.96 (a) Amounts may not add due to rounding.Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2022 Comparison with 2021Xcel 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 Inc. and Other - Earnings decreased $0.07 per share year-to-date due to higher interest charges and decreased earnings from EIP investments. Purchases of Equity Securities by Issuer and Affiliated PurchasersFor the quarter ended Dec. 31, 2022, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers. ITEM 6 - [RESERVED]ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSNon-GAAP Financial MeasuresThe 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. Xcel Energy's management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors' understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies' similarly titled non-GAAP financial measures.Ongoing ROEOngoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity's average stockholder's equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.'s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy's core earnings and underlying performance. 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. **Current (2024):** * $100 invested on Dec. 31, 2018 in stock or index - including reinvestment of dividends. Fiscal years ended Dec. 31. 25 25 25 Table of Contents Table of Contents Purchases of Equity Securities by Issuer and Affiliated PurchasersFor the quarter ended Dec. 31, 2023, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers. ITEM 6 - [RESERVED]ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSNon-GAAP Financial MeasuresThe following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company's financial performance, financial position or cash flows that is adjusted from measures calculated and presented in accordance with GAAP. Xcel Energy's management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors' understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies' similarly titled non-GAAP financial measures.Ongoing ROEOngoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity's average stockholder's equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.'s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy's core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted 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. 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)20232022GAAP net income$1,771 $1,736 Loss on Comanche Unit 3 litigation35 - Workforce reduction expenses72 - Less: tax effect of adjustments(27) - Ongoing earnings$1,851 $1,736 Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 - 0.25 Earnings from equity method investments - WYCO0.04 - 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31) - (0.31)Total (a)$3.21 0.14 $3.35 Twelve Months Ended Dec. 31, 2022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.23 $ - $1.23 PSCo1.33 - 1.33 SPS0.64 - 0.64 NSP-Wisconsin0.23 - 0.23 Earnings from equity method investments - WYCO0.04 - 0.04 Regulated utility (a)3.47 - 3.47 Xcel Energy Inc. and Other(0.29) - (0.29)Total (a)$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. Purchases of Equity Securities by Issuer and Affiliated PurchasersFor the quarter ended Dec. 31, 2023, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers. ITEM 6 - [RESERVED]ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSNon-GAAP Financial MeasuresThe following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company's financial performance, financial position or cash flows that is adjusted from measures calculated and presented in accordance with GAAP. Xcel Energy's management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors' understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies' similarly titled non-GAAP financial measures.Ongoing ROEOngoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity's average stockholder's equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.'s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy's core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted 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. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP. --- ## Modified: Station, Location and Unit at Dec. 31, 2023 **Key changes:** - Reworded sentence: "MW (a) (b) (a)Summer 2023 net dependable capacity." - Reworded sentence: "31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St." **Prior (2023):** MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) Nobles-Nobles County, MN, 133 Units (e) (d) (d) (d) (a)Summer 2022 net dependable capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)Refuse-derived fuel is made from municipal solid waste. (d)Capacity is attainable only when wind conditions are sufficiently available. (e)Repowered in 2022. NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 (a)Summer 2022 net dependable capacity.(b)Refuse-derived fuel is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975335 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 Manchief, CO, 2 Units (e)Natural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 Various locations, 8 UnitsNatural GasVarious251 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Total6,151 (a)Summer 2022 net dependable capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Purchased in 2022. (f)Capacity is attainable only when wind conditions are sufficiently available. NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 **Current (2024):** MW (a) (b) (c) (d) (e) (e) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (f) (e) (e) (e) (e) (e) Northern Wind-Murray County, MN, 37 Units (g) (e) (e) (e) (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023. (c)Based on NSP-Minnesota's ownership of 59%. (d)RDF is made from municipal solid waste. (e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota's wind facilities had a weighted-average capacity factors of 43%. (f)Repowered in 2023. (g)Purchased in 2023. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo's wind facilities had a weighted-average capacity factors of 43%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 --- ## Modified: Off-Balance Sheet Arrangements **Key changes:** - Reworded sentence: "In February 2024, Xcel Energy announced an increase in the annual dividend of 11 cents per share, which represents an increase of 5.3%." - Reworded sentence: "31, 2022Fair value of pension assets$2,690 $2,685 Projected pension obligation (a)2,943 2,871 Funded status$(253)$(186) Projected pension obligation (a) (a)Excludes non-qualified plan of $12 million and $11 million at Dec." - Reworded sentence: "20, 2024, Xcel Energy Inc." **Prior (2023):** Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2023, Xcel Energy announced an increase in the annual dividend of 13 cents per share, which represents an increase of 6.7%. Xcel Energy's dividend policy balances the following: •Projected cash generation. •Projected capital investment. •A reasonable rate of return on shareholder investment. •The impact on Xcel Energy's capital structure and credit ratings. In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See Note 5 to the consolidated financial statements for further information. Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions: (Millions of Dollars)Dec. 31, 2022Dec. 31, 2021Fair value of pension assets$2,685 $3,670 Projected pension obligation (a)2,871 3,718 Funded status$(186)$(48) Projected pension obligation (a) (a)Excludes non-qualified plan of $11 million and $43 million at Dec. 31, 2022 and 2021, respectively. Pension Assumptions20222021Discount rate5.80 %3.08 %Expected long-term rate of return6.93 6.49 Capital SourcesShort-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. As of Feb. 22, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $328 $1,172 $6 $1,178 PSCo700 123 577 5 582 NSP-Minnesota700 186 514 6 520 SPS500 91 409 2 411 NSP-Wisconsin150 29 121 2 123 Total$3,550 $757 $2,793 $21 $2,814 (a)Credit facilities expire in September 2027.(b)Includes outstanding commercial paper and letters of credit.Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2022 and 2021, Xcel Energy had approximately 550 million shares and 544 million shares of common stock outstanding, respectively. 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. **Current (2024):** Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2024, Xcel Energy announced an increase in the annual dividend of 11 cents per share, which represents an increase of 5.3%. Xcel Energy's dividend policy balances the following: •Projected cash generation. •Projected capital investment. •A reasonable rate of return on shareholder investment. •The impact on Xcel Energy's capital structure and credit ratings. In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See Note 5 to the consolidated financial statements for further information. Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions: (Millions of Dollars)Dec. 31, 2023Dec. 31, 2022Fair value of pension assets$2,690 $2,685 Projected pension obligation (a)2,943 2,871 Funded status$(253)$(186) Projected pension obligation (a) (a)Excludes non-qualified plan of $12 million and $11 million at Dec. 31, 2023 and 2022, respectively. Pension Assumptions20232022Discount rate5.49 %5.80 %Expected long-term rate of return6.93 6.93 Capital SourcesShort-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. As of Feb. 20, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $486 $1,014 $2 $1,016 PSCo700 258 442 6 448 NSP-Minnesota700 273 427 10 437 SPS500 99 401 3 404 NSP-Wisconsin150 43 107 8 115 Total$3,550 $1,159 $2,391 $29 $2,420 (a)Credit facilities expire in September 2027.(b)Includes outstanding commercial paper and letters of credit.Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2023 and 2022, Xcel Energy had approximately 555 million shares and 550 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval. Pension Assumptions20232022Discount rate5.49 %5.80 %Expected long-term rate of return6.93 6.93 --- ## Modified: Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives **Key changes:** - Reworded sentence: "Xcel Energy 2024 Earnings Guidance - Xcel Energy's 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.(a) Key assumptions as compared with 2023 actual levels unless noted: •Constructive outcomes in all pending rate case and regulatory proceedings." - Reworded sentence: "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." - Reworded sentence: "• Target a dividend payout ratio of 50% to 60%." - Removed sentence: "ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information." - Reworded sentence: "43 43 43 Table of Contents Table of Contents" **Prior (2023):** 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.(a) 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%. •Capital rider revenue is projected to increase $90 million to $100 million (net of PTCs). •O&M expenses are projected to decline ~2%. •Depreciation expense is projected to increase approximately $130 million to $140 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. •AFUDC - equity is projected to increase $0 million to $10 million. •ETR is projected to be ~(5%) to (7%). (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. 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 annual dividend increases of 5% to 7%. • Target a dividend payout ratio of 60% to 70%. • Maintain senior secured debt credit ratings in the A range. ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference. ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See Item 15-1 for an index of financial statements included herein. See Note 15 to the consolidated financial statements for further information. 44 44 44 Table of Contents Table of Contents **Current (2024):** Xcel Energy 2024 Earnings Guidance - Xcel Energy's 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.(a) 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 increase 1% to 2%. •Depreciation expense is projected to increase approximately $250 million to $260 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. 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 2023 actual ongoing earnings base of $3.35 per share.• Deliver annual dividend increases of 5% to 7%.• Target a dividend payout ratio of 50% to 60%.• Maintain senior secured debt credit ratings in the A range.ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives: • Deliver long-term annual EPS growth of 5% to 7% based off of a 2023 actual ongoing earnings base of $3.35 per share. • Deliver annual dividend increases of 5% to 7%. • Target a dividend payout ratio of 50% to 60%. • Maintain senior secured debt credit ratings in the A range. ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference. ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See Item 15-1 for an index of financial statements included herein. See Note 15 to the consolidated financial statements for further information. 43 43 43 Table of Contents Table of Contents --- ## Modified: Xcel Energy Inc. and Other Results **Key changes:** - Reworded sentence: "and its nonregulated businesses: (Millions of Dollars)20232022Xcel Energy Inc." **Prior (2023):** Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses: Contribution (Millions of Dollars)20222021Xcel Energy Inc. financing costs$(153)$(129)Venture Holdings (a)5 21 Xcel Energy Inc. taxes and other results(12)(12)Total Xcel Energy Inc. and other costs$(160)$(120) Venture Holdings (a) Contribution (Diluted Earnings (Loss) Per Share)20222021Xcel Energy Inc. financing costs$(0.28)$(0.24)Venture Holdings (a)0.01 0.04 Xcel Energy Inc. taxes and other results(0.02)(0.02)Total Xcel Energy Inc. and other costs$(0.29)$(0.22) Venture Holdings (a) (a)Amounts include gains or losses associated with EIP investments. Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries. **Current (2024):** Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses: (Millions of Dollars)20232022Xcel Energy Inc. financing costs$(174)$(153)Venture Holdings (a)3 5 Xcel Energy Inc. taxes and other results(2)(12)Total Xcel Energy Inc. and other costs$(173)$(160) Venture Holdings (a) (Diluted Earnings (Loss) Per Share)20232022Xcel Energy Inc. financing costs$(0.32)$(0.28)Venture Holdings (a)0.01 0.01 Xcel Energy Inc. taxes and other results - (0.02)Total Xcel Energy Inc. and other costs$(0.31)$(0.29) Venture Holdings (a) (a)Amounts include gains or losses associated with EIP investments. Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries. --- ## Modified: Additional Periods for Which a One-Year Extension May Be Requested (c) **Key changes:** - Reworded sentence: "(d) (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%." - Reworded sentence: "31, 2023, Xcel Energy Inc." - Reworded sentence: "31, 2023: (Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $165 $1,335 PSCo700 349 351 NSP-Minnesota700 180 520 SPS500 75 425 NSP-Wisconsin150 60 90 Total$3,550 $829 $2,721" **Prior (2023):** Xcel Energy Inc. (c) (a) Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b) All extension requests are subject to majority bank group approval. (c) The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million. If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2022, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2022: (Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $231 $1,269 PSCo700 321 379 NSP-Minnesota700 222 478 SPS500 36 464 NSP-Wisconsin150 47 103 Total$3,550 $857 $2,693 **Current (2024):** Xcel Energy Inc. (d) (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions. Amounts authorized by state commissions in respective jurisdictions. (c)All extension requests are subject to majority bank group approval. All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million. The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million. If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2023, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2023: (Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $165 $1,335 PSCo700 349 351 NSP-Minnesota700 180 520 SPS500 75 425 NSP-Wisconsin150 60 90 Total$3,550 $829 $2,721 --- ## Modified: Operations could be impacted by war, terrorism or other events. **Key changes:** - Removed sentence: "Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business." - Removed sentence: "While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event." - Removed sentence: "Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced." - Removed sentence: "A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers." - Removed sentence: "A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cyber incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure." **Prior (2023):** Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms. A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cyber incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations.Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility. We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption. In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows. **Current (2024):** Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms. A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility. We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption. In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows. --- ## Modified: Regulatory Accounting **Key changes:** - Reworded sentence: "31, 2023 and 2022, Xcel Energy had regulatory assets of $3.4 billion and $3.9 billion, respectively and regulatory liabilities of $6.4 billion and $6.0 billion, respectively." - Reworded sentence: "31, 2023, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets." - Reworded sentence: "36 36 36 Table of Contents Table of Contents Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes." - Reworded sentence: "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." - Reworded sentence: "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." **Prior (2023):** Xcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income. Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows. As of Dec. 31, 2022 and 2021, Xcel Energy had regulatory assets of $3.9 billion and $3.8 billion, respectively and regulatory liabilities of $6.0 billion and $5.7 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2022, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information. Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized based on an evaluation of expected future taxable income. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.At Dec. 31, 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. 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. 31, 2022. This represents a 272 basis point and 271 basis point increase, respectively, from 2021. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. **Current (2024):** Xcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income. Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows. As of Dec. 31, 2023 and 2022, Xcel Energy had regulatory assets of $3.4 billion and $3.9 billion, respectively and regulatory liabilities of $6.4 billion and $6.0 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2023, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information. 36 36 36 Table of Contents Table of Contents Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.At Dec. 31, 2023, Xcel Energy set the rate of return on assets used to measure pension costs at 6.93%, which is unchanged from the rate set at Dec. 31, 2022. The rate of return used to measure postretirement health care costs is 5.00% at Dec. 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. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2023 pension costs:Pension Costs(Millions of Dollars)+1%-1%Rate of return (a)$(10)$26 Discount rate (a)3 8 (a)These costs include the effects of regulation.Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy's actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.As of Dec. 31, 2023, the initial medical trend cost claim assumptions for Pre-65 was 6.5% and Post-65 was 5.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy's retiree medical plan. 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. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 13 years in 2023).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:•$100 million in January 2024.•$50 million in 2023.•$50 million in 2022.•$131 million in 2021. Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.At Dec. 31, 2023, Xcel Energy set the rate of return on assets used to measure pension costs at 6.93%, which is unchanged from the rate set at Dec. 31, 2022. The rate of return used to measure postretirement health care costs is 5.00% at Dec. 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. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. --- ## Modified: Recovery Mechanisms **Key changes:** - Reworded sentence: "MechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer's bill.DecouplingMechanism 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." - Reworded sentence: "The ECA is revised quarterly.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC." **Prior (2023):** MechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs in Minnesota.Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.RESRecovers cost of renewable generation in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Infrastructure RiderRecovers costs for investments in generation in South Dakota.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Purchased Gas AdjustmentProvides 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.GUIC RiderRecovers 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. The statute authorizing the GUIC Rider is set to expire June 30, 2023.Sales True-upNSP-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. **Current (2024):** MechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers 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 RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. --- ## Modified: A cybersecurity incident or security breach could have a material effect on our business. **Key changes:** - Reworded sentence: "Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error." - Reworded sentence: "20 20 20 Table of Contents Table of Contents Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability." - Reworded sentence: "Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business." - Reworded sentence: "The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability." - Reworded sentence: "If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows." **Prior (2023):** We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. 21 21 21 Table of Contents Table of Contents Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency's Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. **Current (2024):** We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. 20 20 20 Table of Contents Table of Contents Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency's Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows. Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted. Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. --- ## Modified: CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY **Key changes:** - Reworded sentence: "31, 2020537,438,394 $1,344 $7,404 $5,968 $(141)$14,575 Net income1,597 1,597 Other comprehensive income18 18 Dividends declared on common stock ($1.83 per share)(989)(989)Issuances of common stock6,586,875 16 387 403 Share-based compensation12 (4)8 Balance at Dec." **Prior (2023):** (amounts in millions, except per share data; shares in actual amounts) Common Stock IssuedRetained EarningsAccumulated Other Comprehensive LossTotal Common Stockholders' EquitySharesPar ValueAdditional PaidIn CapitalBalance at Dec. 31, 2019524,539,000 $1,311 $6,656 $5,413 $(141)$13,239 Net income1,473 1,473 Dividends declared on common stock ($1.72 per share)(909)(909)Issuances of common stock12,953,869 33 731 764 Repurchases of common stock(54,475) - (4)(4)Share-based compensation21 (7)14 Adoption of ASC Topic 326(2)(2)Balance at Dec. 31, 2020537,438,394 $1,344 $7,404 $5,968 $(141)$14,575 Net Income1,597 1,597 Other comprehensive loss18 18 Dividends declared on common stock ($1.83 per share)(989)(989)Issuances of common stock6,586,875 16 387 403 Share-based compensation12 (4)8 Balance at Dec. 31, 2021544,025,269 $1,360 $7,803 $6,572 $(123)$15,612 Net income1,736 1,736 Other comprehensive income30 30 Dividends declared on common stock ($1.95 per share)(1,066)(1,066)Issuances of common stock5,552,749 14 345 359 Share-based compensation7 (3)4 Balance at Dec. 31, 2022549,578,018 $1,374 $8,155 $7,239 $(93)$16,675 See Notes to Consolidated Financial Statements **Current (2024):** (amounts in millions, except per share data; shares in actual amounts) Common Stock IssuedRetained EarningsAccumulated Other Comprehensive LossTotal Common Stockholders' EquitySharesPar ValueAdditional PaidIn CapitalBalance at Dec. 31, 2020537,438,394 $1,344 $7,404 $5,968 $(141)$14,575 Net income1,597 1,597 Other comprehensive income18 18 Dividends declared on common stock ($1.83 per share)(989)(989)Issuances of common stock6,586,875 16 387 403 Share-based compensation12 (4)8 Balance at Dec. 31, 2021544,025,269 $1,360 $7,803 $6,572 $(123)$15,612 Net Income1,736 1,736 Other comprehensive loss30 30 Dividends declared on common stock ($1.95 per share)(1,066)(1,066)Issuances of common stock5,552,749 14 345 359 Share-based compensation7 (3)4 Balance at Dec. 31, 2022549,578,018 $1,374 $8,155 $7,239 $(93)$16,675 Net income1,771 1,771 Other comprehensive income(1)(1)Dividends declared on common stock ($2.08 per share)(1,148)(1,148)Issuances of common stock5,363,685 13 295 308 Share-based compensation15 (4)11 Balance at Dec. 31, 2023554,941,703 $1,387 $8,465 $7,858 $(94)$17,616 See Notes to Consolidated Financial Statements --- ## Modified: Failure to attract and retain a qualified workforce could have an adverse effect on operations. **Key changes:** - Reworded sentence: "The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning." - Reworded sentence: "Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business." **Prior (2023):** The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire and adequately train replacement employees, including the transfer of significant knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees adversely impacts our results of operations, financial condition or cash flows. **Current (2024):** The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows. Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs. --- ## Modified: Investing Cash Flows **Key changes:** - Reworded sentence: "31Cash used in investing activities - 2022$(4,653)Components of change - 2023 vs." **Prior (2023):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2021$(4,287)Components of change - 2022 vs. 2021Increased capital expenditures(394)Other investing activities28 Cash used in investing activities - 2022$(4,653) Net cash used in investing activities increased by $366 million for 2022 as compared to 2021. The increase in capital expenditures was largely due to continued system expansion. **Current (2024):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2022$(4,653)Components of change - 2023 vs. 2022Increased capital expenditures(1,216)Other investing activities(57)Cash used in investing activities - 2023$(5,926) Net cash used in investing activities increased by $1,273 million for 2023 as compared to 2022. The increase in capital expenditures was largely due to continued system expansion. --- ## Modified: Purchased Power and Transmission Service Providers **Key changes:** - Reworded sentence: "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." - Reworded sentence: "Much of PSCo's long-term purchased power is for wind, solar and storage resources." **Prior (2023):** 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. 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. Energy imbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost. Purchased Transmission Services - In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers. **Current (2024):** PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs. Purchased Power - PSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of PSCo's long-term purchased power is for wind, solar and storage resources. PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost. Energy Markets - PSCo joined the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in an organized wholesale market. Energy imbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost. Purchased Transmission Services - In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers. --- ## Modified: Purchased Power and Transmission Services **Key changes:** - Added sentence: "Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers." - Added sentence: "Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge." - Added sentence: "NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products." - Added sentence: "NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases." - Added sentence: "NSP-Minnesota also engages in trading activity unrelated to these hedging activities." **Prior (2023):** The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers. **Current (2024):** The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.Wholesale and Commodity Marketing OperationsNSP-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. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance. Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers. --- ## Modified: Public Utility Regulation **Key changes:** - Reworded sentence: "The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate." - Reworded sentence: "Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information.NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.Reviews and approves natural gas supply plans.NDPSCRetail rates, services and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.Pipeline safety compliance.SDPUCRetail rates, services and other aspects of electric operations.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.MISONSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets." - Added sentence: "Rates are designed to recover plant investment, operating costs and an allowed return on investment." - Added sentence: "Our utility subsidiaries request changes in utility rates through commission filings." - Added sentence: "Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates." **Prior (2023):** A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2020 to Dec. 31, 2021 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2021, which was filed with the SEC on Feb. 23, 2022. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters within Note 12 to the consolidated financial statements for further information.NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.Reviews and approves natural gas supply plans.NDPSCRetail rates, services and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.Pipeline safety compliance.SDPUCRetail rates, services and other aspects of electric operations.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.MISONSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance. **Current (2024):** The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas. 29 29 29 Table of Contents Table of Contents Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information.NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.Reviews and approves natural gas supply plans.NDPSCRetail rates, services and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.Pipeline safety compliance.SDPUCRetail rates, services and other aspects of electric operations.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.MISONSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers 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 RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. (a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 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. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In October 2023, the MPUC denied NSP-Minnesota's request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023.2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota's request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).Next steps in the procedural schedule are expected to be as follows:•Intervenor direct testimony: April 19, 2024•Rebuttal testimony: May 24, 2024•Evidentiary hearings: July 10-12, 2024•ALJ Report: October 28, 2024•MPUC Order Due: March 14, 2025 Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information.NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.Reviews and approves natural gas supply plans.NDPSCRetail rates, services and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.Pipeline safety compliance.SDPUCRetail rates, services and other aspects of electric operations.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.MISONSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance. Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality. See Rate Matters and Other within Note 12 to the consolidated financial statements for further information. --- ## Modified: Nuclear Power Operations **Key changes:** - Reworded sentence: "Currently, there are no definitive plans for a permanent federal storage facility site." - Reworded sentence: "NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause." **Prior (2023):** Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use. NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs. Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable. High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and 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. 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 OperationsNSP-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 Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site. Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and 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. 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. **Current (2024):** Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use. NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs. Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable. High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site. Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054. In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin's natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-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 AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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.Recently Concluded Regulatory ProceedingsWisconsin 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. --- ## Modified: Station, Location and Unit at Dec. 31, 2023 **Key changes:** - Reworded sentence: "MW (a) (b) (c) Hayden-Hayden, CO, 2 Units (d) (e) (e) (a)Summer 2023 net dependable capacity." - Reworded sentence: "(e)Net maximum capacity is attainable only when wind conditions are sufficiently available." - Reworded sentence: "31, 2023FuelInstalledMW (a)Steam:Cunningham-Hobbs, NM, 1 UnitNatural Gas1957 - 1965183 (b)Harrington-Amarillo, TX, 3 UnitsCoal1976 - 19801,018 Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 Plant X-Earth, TX, 1 UnitNatural Gas1952 - 1964190 (b)Tolk-Muleshoe, TX, 2 UnitsCoal1982 - 19851,067 Combustion Turbine:Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 Wind:Hale-Plainview, TX, 239 UnitsWind2019478 (c)Sagamore-Dora, NM, 240 UnitsWind2020507 (c)Total5,100 (a)Summer 2023 net dependable capacity." - Reworded sentence: "31, 2018 in stock or index - including reinvestment of dividends." - Reworded sentence: "31, 2023FuelInstalledMW (a)Steam:Cunningham-Hobbs, NM, 1 UnitNatural Gas1957 - 1965183 (b)Harrington-Amarillo, TX, 3 UnitsCoal1976 - 19801,018 Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 Plant X-Earth, TX, 1 UnitNatural Gas1952 - 1964190 (b)Tolk-Muleshoe, TX, 2 UnitsCoal1982 - 19851,067 Combustion Turbine:Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 Wind:Hale-Plainview, TX, 239 UnitsWind2019478 (c)Sagamore-Dora, NM, 240 UnitsWind2020507 (c)Total5,100 (a)Summer 2023 net dependable capacity." **Prior (2023):** MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) Nobles-Nobles County, MN, 133 Units (e) (d) (d) (d) (a)Summer 2022 net dependable capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)Refuse-derived fuel is made from municipal solid waste. (d)Capacity is attainable only when wind conditions are sufficiently available. (e)Repowered in 2022. NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 (a)Summer 2022 net dependable capacity.(b)Refuse-derived fuel is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975335 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 Manchief, CO, 2 Units (e)Natural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 Various locations, 8 UnitsNatural GasVarious251 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Total6,151 (a)Summer 2022 net dependable capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Purchased in 2022. (f)Capacity is attainable only when wind conditions are sufficiently available. NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 **Current (2024):** MW (a) (b) (c) (d) (e) (e) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (f) (e) (e) (e) (e) (e) Northern Wind-Murray County, MN, 37 Units (g) (e) (e) (e) (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023. (c)Based on NSP-Minnesota's ownership of 59%. (d)RDF is made from municipal solid waste. (e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota's wind facilities had a weighted-average capacity factors of 43%. (f)Repowered in 2023. (g)Purchased in 2023. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo's wind facilities had a weighted-average capacity factors of 43%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 --- ## Modified: Additional Information **Key changes:** - Reworded sentence: "Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers 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 RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service." - Reworded sentence: "The rate request was based on a ROE of 10.2%, a 52.5% equity ratio and forward test years." **Prior (2023):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. 29 29 29 Table of Contents Table of Contents Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs in Minnesota.Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.RESRecovers cost of renewable generation in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Infrastructure RiderRecovers costs for investments in generation in South Dakota.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Purchased Gas AdjustmentProvides 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.GUIC RiderRecovers 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. The statute authorizing the GUIC Rider is set to expire June 30, 2023.Sales True-upNSP-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.(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 Minnesota Electric Rate Case - In 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.In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/AIn 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows:•ALJ Report: March 31, 2023.•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. 1, 2022.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. 1, 2021. 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. 1, 2022.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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs in Minnesota.Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.RESRecovers cost of renewable generation in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Infrastructure RiderRecovers costs for investments in generation in South Dakota.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Purchased Gas AdjustmentProvides 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.GUIC RiderRecovers 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. The statute authorizing the GUIC Rider is set to expire June 30, 2023.Sales True-upNSP-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.(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 Minnesota Electric Rate Case - In 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.In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/A **Current (2024):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers 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 RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. (a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Pending and Recently Concluded Regulatory Proceedings2022 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. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In October 2023, the MPUC denied NSP-Minnesota's request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023.2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota's request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).Next steps in the procedural schedule are expected to be as follows:•Intervenor direct testimony: April 19, 2024•Rebuttal testimony: May 24, 2024•Evidentiary hearings: July 10-12, 2024•ALJ Report: October 28, 2024•MPUC Order Due: March 14, 2025 --- ## Modified: (Millions of Dollars)Year Ended Dec. 31AverageHighLow2023$ - $ - $1 $ - 20222 1 5 - **Key changes:** - Reworded sentence: "39 39 39 Table of Contents Table of Contents 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." - Reworded sentence: "Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $9 million and $8 million in 2023 and 2022, respectively." - Reworded sentence: "31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $24 million." - Reworded sentence: "Distress in the financial markets could increase our credit risk.Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value." - Reworded sentence: "Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $9 million and $8 million in 2023 and 2022, respectively." **Prior (2023):** We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans. Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. 39 39 39 Table of Contents Table of Contents Fair value of net commodity trading contracts as of Dec. 31, 2022:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(8)$(6)$(7)$(2)$(23)NSP-Minnesota (b)5 (4) - (3)(2)PSCo (a)10 3 3 - 16 PSCo (b)(56)(15)8 - (63)$(49)$(22)$4 $(5)$(72)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $ - $ - $15 $15 PSCo (b)40 7 - - 47 $40 $7 $ - $15 $62 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20222021Fair value of commodity trading net contracts outstanding at Jan. 1$(33)$(54)Contracts realized or settled during the period(15)(54)Commodity trading contract additions and changes during the period38 75 Fair value of commodity trading net contracts outstanding at Dec. 31$(10)$(33)A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $8 million at Dec. 31, 2022 and $13 million at Dec. 31, 2021. 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. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2022$2 $1 $5 $ - 2021$1 $2 $52 $1 A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On 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. 19, 2021.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. NSP-Minnesota is scheduled to take delivery of approximately 26% 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. Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $8 million and $11 million in 2022 and 2021, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $56 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $47 million. At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $36 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $26 million.Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk. Fair value of net commodity trading contracts as of Dec. 31, 2022:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(8)$(6)$(7)$(2)$(23)NSP-Minnesota (b)5 (4) - (3)(2)PSCo (a)10 3 3 - 16 PSCo (b)(56)(15)8 - (63)$(49)$(22)$4 $(5)$(72)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $ - $ - $15 $15 PSCo (b)40 7 - - 47 $40 $7 $ - $15 $62 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20222021Fair value of commodity trading net contracts outstanding at Jan. 1$(33)$(54)Contracts realized or settled during the period(15)(54)Commodity trading contract additions and changes during the period38 75 Fair value of commodity trading net contracts outstanding at Dec. 31$(10)$(33)A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $8 million at Dec. 31, 2022 and $13 million at Dec. 31, 2021. 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. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2022$2 $1 $5 $ - 2021$1 $2 $52 $1 A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On 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 $1 million by Feb. 19, 2021. Fair value of net commodity trading contracts as of Dec. 31, 2022:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(8)$(6)$(7)$(2)$(23)NSP-Minnesota (b)5 (4) - (3)(2)PSCo (a)10 3 3 - 16 PSCo (b)(56)(15)8 - (63)$(49)$(22)$4 $(5)$(72) NSP-Minnesota (a) NSP-Minnesota (b) PSCo (a) PSCo (b) Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $ - $ - $15 $15 PSCo (b)40 7 - - 47 $40 $7 $ - $15 $62 NSP-Minnesota (b) PSCo (b) (a)Prices actively quoted or based on actively quoted prices. (b)Prices based on models and other valuation methods. Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31: (Millions of Dollars)20222021Fair value of commodity trading net contracts outstanding at Jan. 1$(33)$(54)Contracts realized or settled during the period(15)(54)Commodity trading contract additions and changes during the period38 75 Fair value of commodity trading net contracts outstanding at Dec. 31$(10)$(33) A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $8 million at Dec. 31, 2022 and $13 million at Dec. 31, 2021. 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. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows: (Millions of Dollars)Year Ended Dec. 31AverageHighLow2022$2 $1 $5 $ - 2021$1 $2 $52 $1 A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On 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. 19, 2021. 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. NSP-Minnesota is scheduled to take delivery of approximately 26% 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. Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $8 million and $11 million in 2022 and 2021, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $56 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $47 million. At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $36 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $26 million.Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk. 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. NSP-Minnesota is scheduled to take delivery of approximately 26% 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. Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives. A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $8 million and $11 million in 2022 and 2021, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs. The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations. At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $56 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $47 million. At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $36 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $26 million. Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk. 40 40 40 Table of Contents Table of Contents Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2021$2,189 Components of change - 2022 vs. 2021Higher net income139 Non-cash transactions257 Changes in working capital(300)Changes in net regulatory and other assets and liabilities 1,647 Cash provided by operating activities - 2022$3,932 Net cash provided by operating activities increased by $1,743 million for 2022 as compared to 2021. The increase was primarily due to the deferral of net natural gas, fuel and purchased energy costs incurred during Winter Storm Uri in the first quarter of 2021. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2021$(4,287)Components of change - 2022 vs. 2021Increased capital expenditures(394)Other investing activities28 Cash used in investing activities - 2022$(4,653)Net cash used in investing activities increased by $366 million for 2022 as compared to 2021. The increase in capital expenditures was largely due to continued system expansion.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2021$2,135 Components of change - 2022 vs. 2021Lower debt issuances(1,159)Higher repayments of long-term debt(184)Lower proceeds from issuance of common stock(44)Higher dividends paid to shareholders(77)Other financing activities(5)Cash provided by financing activities - 2022$666 Net cash provided by financing activities decreased by $1,469 million for 2022 as compared to 2021. The decrease was primarily related to the amount/timing of debt issuances and repayments associated with Winter Storm Uri.See Note 5 to the consolidated financial statements for further information.Capital RequirementsXcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy's financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, 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. Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2021$2,189 Components of change - 2022 vs. 2021Higher net income139 Non-cash transactions257 Changes in working capital(300)Changes in net regulatory and other assets and liabilities 1,647 Cash provided by operating activities - 2022$3,932 Net cash provided by operating activities increased by $1,743 million for 2022 as compared to 2021. The increase was primarily due to the deferral of net natural gas, fuel and purchased energy costs incurred during Winter Storm Uri in the first quarter of 2021. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2021$(4,287)Components of change - 2022 vs. 2021Increased capital expenditures(394)Other investing activities28 Cash used in investing activities - 2022$(4,653)Net cash used in investing activities increased by $366 million for 2022 as compared to 2021. The increase in capital expenditures was largely due to continued system expansion.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2021$2,135 Components of change - 2022 vs. 2021Lower debt issuances(1,159)Higher repayments of long-term debt(184)Lower proceeds from issuance of common stock(44)Higher dividends paid to shareholders(77)Other financing activities(5)Cash provided by financing activities - 2022$666 **Current (2024):** 39 39 39 Table of Contents Table of Contents 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. 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. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $9 million and $8 million in 2023 and 2022, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $24 million. At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $56 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $47 million.Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2022$3,932 Components of change - 2023 vs. 2022Higher net income35 Non-cash transactions88 Changes in working capital900 Changes in net regulatory and other assets and liabilities 372 Cash provided by operating activities - 2023$5,327 Net cash provided by operating activities increased by $1,395 million for 2023 as compared to 2022. The increase was largely due to continued collections of prior year deferred net natural gas, fuel and purchased energy costs, as well as the impact of decreased natural gas prices on accounts payable and receivables. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2022$(4,653)Components of change - 2023 vs. 2022Increased capital expenditures(1,216)Other investing activities(57)Cash used in investing activities - 2023$(5,926)Net cash used in investing activities increased by $1,273 million for 2023 as compared to 2022. The increase in capital expenditures was largely due to continued system expansion.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2022$666 Components of change - 2023 vs. 2022Higher debt issuances, net of repayments80 Lower proceeds from issuance of common stock(52)Higher dividends paid to shareholders(80)Other financing activities3 Cash provided by financing activities - 2023$617 Net cash provided by financing activities decreased by $49 million for 2023 as compared to 2022. The decrease was largely related to the amount/timing of debt issuances and repayments.See Note 5 to the consolidated financial statements for further information. 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. 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. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $9 million and $8 million in 2023 and 2022, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $24 million. At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $56 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $47 million.Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk. 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. 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. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives. A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $9 million and $8 million in 2023 and 2022, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs. The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations. At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $24 million. At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $56 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $47 million. Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk. Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2022$3,932 Components of change - 2023 vs. 2022Higher net income35 Non-cash transactions88 Changes in working capital900 Changes in net regulatory and other assets and liabilities 372 Cash provided by operating activities - 2023$5,327 Net cash provided by operating activities increased by $1,395 million for 2023 as compared to 2022. The increase was largely due to continued collections of prior year deferred net natural gas, fuel and purchased energy costs, as well as the impact of decreased natural gas prices on accounts payable and receivables. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2022$(4,653)Components of change - 2023 vs. 2022Increased capital expenditures(1,216)Other investing activities(57)Cash used in investing activities - 2023$(5,926)Net cash used in investing activities increased by $1,273 million for 2023 as compared to 2022. The increase in capital expenditures was largely due to continued system expansion.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2022$666 Components of change - 2023 vs. 2022Higher debt issuances, net of repayments80 Lower proceeds from issuance of common stock(52)Higher dividends paid to shareholders(80)Other financing activities3 Cash provided by financing activities - 2023$617 Net cash provided by financing activities decreased by $49 million for 2023 as compared to 2022. The decrease was largely related to the amount/timing of debt issuances and repayments.See Note 5 to the consolidated financial statements for further information. --- ## Modified: Recovery Mechanisms **Key changes:** - Reworded sentence: "MechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers 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 RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service." **Prior (2023):** MechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs in Minnesota.Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.RESRecovers cost of renewable generation in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Infrastructure RiderRecovers costs for investments in generation in South Dakota.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Purchased Gas AdjustmentProvides 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.GUIC RiderRecovers 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. The statute authorizing the GUIC Rider is set to expire June 30, 2023.Sales True-upNSP-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. **Current (2024):** MechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers 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 RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. --- ## Modified: Other Utility Items **Key changes:** - Reworded sentence: "AFUDC - Alternative Revenue - Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs." - Removed sentence: "Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees." - Removed sentence: "The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues." - Removed sentence: "Nuclear Refueling Outage Costs - Xcel Energy uses a deferral and amortization method for nuclear refueling costs." - Removed sentence: "This method amortizes costs over the period between refueling outages consistent with rate recovery." **Prior (2023):** AFUDC - AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy's rate base. AFUDC - 55 55 55 Table of Contents Table of Contents Alternative Revenue - Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs - Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.Nuclear Refueling Outage Costs - Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are on a net basis in electric operating revenues in the consolidated statements of income.2. Accounting PronouncementsAs of Dec. 31, 2022, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy's consolidated financial statements.3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2022Dec. 31, 2021Property, plant and equipment, netElectric plant$49,639 $48,680 Natural gas plant8,514 7,758 Common and other property2,970 2,602 Plant to be retired (a)2,217 1,200 CWIP2,124 1,969 Total property, plant and equipment65,464 62,209 Less accumulated depreciation(17,502)(17,060)Nuclear fuel3,183 3,081 Less accumulated amortization(2,892)(2,773)Property, plant and equipment, net$48,253 $45,457 (a)Amounts as of Dec. 31, 2021 include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 1 and 2 and Craig Units 1 and 2 for PSCo; and Tolk and coal generation assets at Harrington pending facility gas conversion for SPS. Following the June 2022 approval of PSCo's revised resource plan settlement, amounts as of Dec. 31, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion as well as the removal of Comanche Unit 1 that was retired in 2022. Amounts are presented net of accumulated depreciation. Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec. 31, 2022:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$623 $468 59 %Sherco common facilities180 115 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 3 50 Huntley Wilmarth49 1 50 CapX2020818 124 51 Total NSP-Minnesota (a)$1,686 $715 (a)Projects additionally include $4 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$177 $20 37 %CapX2020166 34 80 Total NSP-Wisconsin (a)$343 $54 (a)Projects additionally include $1 million in CWIP. Alternative Revenue - Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs - Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.Nuclear Refueling Outage Costs - Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are on a net basis in electric operating revenues in the consolidated statements of income.2. Accounting PronouncementsAs of Dec. 31, 2022, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy's consolidated financial statements. Alternative Revenue - Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs - Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues. Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues. Nuclear Refueling Outage Costs - Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. Nuclear Refueling Outage Costs - Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are on a net basis in electric operating revenues in the consolidated statements of income. **Current (2024):** AFUDC - AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy's rate base. AFUDC - Alternative Revenue - Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs - Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues. Nuclear Refueling Outage Costs - Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.2. Accounting PronouncementsRecently IssuedSegment Reporting - In November 2023, the FASB issued ASU 2023-07 - Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. Income Taxes - In December 2023, the FASB issued ASU 2023-09 - Income Taxes (Topic 740) - Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the effective tax rate reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. 3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2023Dec. 31, 2022Property, plant and equipment, netElectric plant$52,494 $49,639 Natural gas plant9,080 8,514 Common and other property3,190 2,970 Plant to be retired (a)2,055 2,217 CWIP2,873 2,124 Total property, plant and equipment69,692 65,464 Less accumulated depreciation(18,399)(17,502)Nuclear fuel3,337 3,183 Less accumulated amortization(2,988)(2,892)Property, plant and equipment, net$51,642 $48,253 (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS. The Dec. 31, 2022 balance also includes Sherco 2, which was retired on Dec. 31, 2023. Amounts are presented net of accumulated depreciation. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income. --- ## Modified: Long-Term Borrowings and Other Financing Instruments **Key changes:** - Reworded sentence: "31 (in millions of dollars):Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20232022Unsecured senior notes0.50 %Oct." - Reworded sentence: "1, 2049500 500 Unamortized discount(8)(7)Unamortized debt issuance cost(36)(35)Current maturities - (500)Total long-term debt$6,136 $5,338 (a)2022 financing.(b)2023 financing." - Reworded sentence: "15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sept." - Reworded sentence: "31 (in millions of dollars): Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20232022Unsecured senior notes0.50 %Oct." - Reworded sentence: "1, 2049500 500 Unamortized discount(8)(7)Unamortized debt issuance cost(36)(35)Current maturities - (500)Total long-term debt$6,136 $5,338 Unsecured senior notes Unsecured senior notes (a) Unsecured senior notes (b) (a)2022 financing." **Prior (2023):** Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars):Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20222021Unsecured senior notes0.50 Oct. 15, 2023500 500 Unsecured senior notes3.30 June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes (a)1.75 March 15,2027500 500 Unsecured senior notes 4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes 2.60 Dec. 1, 2029500 500 Unsecured senior notes3.40 June 1, 2030600 600 Unsecured senior notes (a)2.35 Nov. 15, 2031300 300 Unsecured senior notes (b)4.60 June 1, 2032700 - Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sep. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(7)(8)Unamortized debt issuance cost(35)(33)Current maturities (500) - Total long-term debt$5,338 $5,139 (a)2021 financing.(b)2022 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20222021First mortgage bonds2.15 %Aug. 15, 2022$ - $300 First mortgage bonds2.60 May 15, 2023400 400 First mortgage bonds7.125 July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds (a)2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sep. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds (a)3.20 April 1,2052425 425 First mortgage bonds (b)4.50 June 1, 2052500 - Other long-term debt3 3 Unamortized discount(45)(44)Unamortized debt issuance cost(66)(62)Current maturities(400)(300)Total long-term debt$6,542 $6,447 (a)2021 financing.(b)2022 financing. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars): Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20222021Unsecured senior notes0.50 Oct. 15, 2023500 500 Unsecured senior notes3.30 June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes (a)1.75 March 15,2027500 500 Unsecured senior notes 4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes 2.60 Dec. 1, 2029500 500 Unsecured senior notes3.40 June 1, 2030600 600 Unsecured senior notes (a)2.35 Nov. 15, 2031300 300 Unsecured senior notes (b)4.60 June 1, 2032700 - Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sep. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(7)(8)Unamortized debt issuance cost(35)(33)Current maturities (500) - Total long-term debt$5,338 $5,139 Unsecured senior notes (a) Unsecured senior notes (a) Unsecured senior notes (b) (a)2021 financing. (b)2022 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20222021First mortgage bonds2.15 %Aug. 15, 2022$ - $300 First mortgage bonds2.60 May 15, 2023400 400 First mortgage bonds7.125 July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds (a)2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sep. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds (a)3.20 April 1,2052425 425 First mortgage bonds (b)4.50 June 1, 2052500 - Other long-term debt3 3 Unamortized discount(45)(44)Unamortized debt issuance cost(66)(62)Current maturities(400)(300)Total long-term debt$6,542 $6,447 First mortgage bonds (a) First mortgage bonds (a) First mortgage bonds (b) (a)2021 financing. (b)2022 financing. **Current (2024):** Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars):Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20232022Unsecured senior notes0.50 %Oct. 15, 2023$ - $500 Unsecured senior notes3.30 June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes1.75 March 15, 2027500 500 Unsecured senior notes4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes2.60 Dec. 1, 2029500 500 Unsecured senior notes 3.40 June 1, 2030600 600 Unsecured senior notes 2.35 Nov. 15, 2031300 300 Unsecured senior notes (a)4.60 June 1, 2032700 700 Unsecured senior notes (b)5.45 Aug. 15, 2033800 - Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sept. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(8)(7)Unamortized debt issuance cost(36)(35)Current maturities - (500)Total long-term debt$6,136 $5,338 (a)2022 financing.(b)2023 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds2.60 %May 15, 2023$ - $400 First mortgage bonds7.125 July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds 6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sept. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds3.20 April 1, 2052425 425 First mortgage bonds (a)4.50 June 1, 2052500 500 First mortgage bonds (b)5.10 May 15, 2053800 - Other long-term debt2 3 Unamortized discount(49)(45)Unamortized debt issuance cost(73)(66)Current maturities - (400)Total long-term debt$7,330 $6,542 (a)2022 financing.(b)2023 financing. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars): Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20232022Unsecured senior notes0.50 %Oct. 15, 2023$ - $500 Unsecured senior notes3.30 June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes1.75 March 15, 2027500 500 Unsecured senior notes4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes2.60 Dec. 1, 2029500 500 Unsecured senior notes 3.40 June 1, 2030600 600 Unsecured senior notes 2.35 Nov. 15, 2031300 300 Unsecured senior notes (a)4.60 June 1, 2032700 700 Unsecured senior notes (b)5.45 Aug. 15, 2033800 - Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sept. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(8)(7)Unamortized debt issuance cost(36)(35)Current maturities - (500)Total long-term debt$6,136 $5,338 Unsecured senior notes Unsecured senior notes (a) Unsecured senior notes (b) (a)2022 financing. (b)2023 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds2.60 %May 15, 2023$ - $400 First mortgage bonds7.125 July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds 6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sept. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds3.20 April 1, 2052425 425 First mortgage bonds (a)4.50 June 1, 2052500 500 First mortgage bonds (b)5.10 May 15, 2053800 - Other long-term debt2 3 Unamortized discount(49)(45)Unamortized debt issuance cost(73)(66)Current maturities - (400)Total long-term debt$7,330 $6,542 First mortgage bonds (a) First mortgage bonds (b) (a)2022 financing. 2022 financing. (b)2023 financing. 59 59 59 Table of Contents Table of Contents NSP-WisconsinFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds3.30 %June 15, 2024$100 $100 First mortgage bonds3.30 June 15, 2024100 100 First mortgage bonds6.375 Sept. 1, 2038200 200 First mortgage bonds3.70 Oct. 1, 2042100 100 First mortgage bonds3.75 Dec. 1, 2047100 100 First mortgage bonds4.20 Sept. 1, 2048200 200 First mortgage bonds 3.05 May 1, 2051100 100 First mortgage bonds2.82 May 1, 2051100 100 First mortgage bonds (a)4.86 Sept. 15, 2052100 100 First mortgage bonds (b)5.30 June 15, 2053125 - Unamortized discount(3)(3)Unamortized debt issuance cost(11)(11)Current maturities(200) - Total long-term debt$1,011 $1,086 (a)2022 financing. (b)2023 financing.PSCoFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds2.50 %March 15, 2023$ - $250 First mortgage bonds2.90 May 15, 2025250 250 First mortgage bonds3.70 June 15, 2028350 350 First mortgage bonds1.90 Jan. 15, 2031375 375 First mortgage bonds 1.875 June 15, 2031750 750 First mortgage bonds (a)4.10 June 1, 2032300 300 First mortgage bonds6.25 Sept. 1, 2037350 350 First mortgage bonds6.50 Aug. 1, 2038300 300 First mortgage bonds4.75 Aug. 15, 2041250 250 First mortgage bonds3.60 Sept. 15, 2042500 500 First mortgage bonds3.95 March 15, 2043250 250 First mortgage bonds4.30 March 15, 2044300 300 First mortgage bonds3.55 June 15, 2046250 250 First mortgage bonds3.80 June 15, 2047400 400 First mortgage bonds4.10 June 15, 2048350 350 First mortgage bonds4.05 Sept. 15, 2049400 400 First mortgage bonds3.20 March 1, 2050550 550 First mortgage bonds2.70 Jan. 15, 2051375 375 First mortgage bonds (a)4.50 June 1, 2052400 400 First mortgage bonds (b)5.25 April 1, 2053850 - Unamortized discount(41)(37)Unamortized debt issuance cost(59)(53)Current maturities - (250)Total long-term debt$7,450 $6,610 (a)2022 financing.(b)2023 financing. SPSFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds3.30 %June 15, 2024$150 $150 First mortgage bonds3.30 June 15, 2024200 200 Unsecured senior notes6.00 Oct. 1, 2033100 100 Unsecured senior notes6.00 Oct. 1, 2036250 250 First mortgage bonds4.50 Aug. 15, 2041200 200 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds3.40 Aug. 15, 2046300 300 First mortgage bonds3.70 Aug. 15, 2047450 450 First mortgage bonds4.40 Nov. 15, 2048300 300 First mortgage bonds 3.75 June 15, 2049300 300 First mortgage bonds3.15 May 1, 2050350 350 First mortgage bonds3.15 May 1, 2050250 250 First mortgage bonds (a)5.15 June 1, 2052200 200 First mortgage bonds (b)6.00 Sept. 15, 2053100 - Unamortized discount(10)(10)Unamortized debt issuance cost(29)(29)Current maturities(350) - Total long-term debt$2,961 $3,211 (a)2022 financing.(b)2023 financing.Other SubsidiariesFinancing InstrumentInterest RateMaturity Date20232022Various Eloigne affordable housing project notes0.00% - 8.00%2024 - 2055$27 $27 Current maturities(2)(1)Total long-term debt$25 $26 Maturities of long-term debt:(Millions of Dollars)2024$552 20251,103 2026501 2027501 20281,133 Deferred Financing Costs - Deferred financing costs of approximately $209 million and $193 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2023 and 2022, respectively. Equity through DRIP and Benefits Program - Xcel Energy issued $88 million of equity in 2023 and $84 million of equity in 2022 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.ATM Equity Offering - In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares of common stock were issued (approximately $350 million in net proceeds and $3 million in transaction fees paid). In 2022, 4.30 million shares of common stock were issued (approximately $300 million in net proceeds and $3 million in transaction fees paid). In 2023, 0.90 million shares of common stock were issued ($62 million in net proceeds and $1 million in transaction fees paid). In October 2023, the 2021 ATM offering was closed. NSP-WisconsinFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds3.30 %June 15, 2024$100 $100 First mortgage bonds3.30 June 15, 2024100 100 First mortgage bonds6.375 Sept. 1, 2038200 200 First mortgage bonds3.70 Oct. 1, 2042100 100 First mortgage bonds3.75 Dec. 1, 2047100 100 First mortgage bonds4.20 Sept. 1, 2048200 200 First mortgage bonds 3.05 May 1, 2051100 100 First mortgage bonds2.82 May 1, 2051100 100 First mortgage bonds (a)4.86 Sept. 15, 2052100 100 First mortgage bonds (b)5.30 June 15, 2053125 - Unamortized discount(3)(3)Unamortized debt issuance cost(11)(11)Current maturities(200) - Total long-term debt$1,011 $1,086 (a)2022 financing. (b)2023 financing.PSCoFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds2.50 %March 15, 2023$ - $250 First mortgage bonds2.90 May 15, 2025250 250 First mortgage bonds3.70 June 15, 2028350 350 First mortgage bonds1.90 Jan. 15, 2031375 375 First mortgage bonds 1.875 June 15, 2031750 750 First mortgage bonds (a)4.10 June 1, 2032300 300 First mortgage bonds6.25 Sept. 1, 2037350 350 First mortgage bonds6.50 Aug. 1, 2038300 300 First mortgage bonds4.75 Aug. 15, 2041250 250 First mortgage bonds3.60 Sept. 15, 2042500 500 First mortgage bonds3.95 March 15, 2043250 250 First mortgage bonds4.30 March 15, 2044300 300 First mortgage bonds3.55 June 15, 2046250 250 First mortgage bonds3.80 June 15, 2047400 400 First mortgage bonds4.10 June 15, 2048350 350 First mortgage bonds4.05 Sept. 15, 2049400 400 First mortgage bonds3.20 March 1, 2050550 550 First mortgage bonds2.70 Jan. 15, 2051375 375 First mortgage bonds (a)4.50 June 1, 2052400 400 First mortgage bonds (b)5.25 April 1, 2053850 - Unamortized discount(41)(37)Unamortized debt issuance cost(59)(53)Current maturities - (250)Total long-term debt$7,450 $6,610 (a)2022 financing.(b)2023 financing. NSP-WisconsinFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds3.30 %June 15, 2024$100 $100 First mortgage bonds3.30 June 15, 2024100 100 First mortgage bonds6.375 Sept. 1, 2038200 200 First mortgage bonds3.70 Oct. 1, 2042100 100 First mortgage bonds3.75 Dec. 1, 2047100 100 First mortgage bonds4.20 Sept. 1, 2048200 200 First mortgage bonds 3.05 May 1, 2051100 100 First mortgage bonds2.82 May 1, 2051100 100 First mortgage bonds (a)4.86 Sept. 15, 2052100 100 First mortgage bonds (b)5.30 June 15, 2053125 - Unamortized discount(3)(3)Unamortized debt issuance cost(11)(11)Current maturities(200) - Total long-term debt$1,011 $1,086 First mortgage bonds (a) First mortgage bonds (b) (a)2022 financing. 2022 financing. (b)2023 financing. 2023 financing. PSCoFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds2.50 %March 15, 2023$ - $250 First mortgage bonds2.90 May 15, 2025250 250 First mortgage bonds3.70 June 15, 2028350 350 First mortgage bonds1.90 Jan. 15, 2031375 375 First mortgage bonds 1.875 June 15, 2031750 750 First mortgage bonds (a)4.10 June 1, 2032300 300 First mortgage bonds6.25 Sept. 1, 2037350 350 First mortgage bonds6.50 Aug. 1, 2038300 300 First mortgage bonds4.75 Aug. 15, 2041250 250 First mortgage bonds3.60 Sept. 15, 2042500 500 First mortgage bonds3.95 March 15, 2043250 250 First mortgage bonds4.30 March 15, 2044300 300 First mortgage bonds3.55 June 15, 2046250 250 First mortgage bonds3.80 June 15, 2047400 400 First mortgage bonds4.10 June 15, 2048350 350 First mortgage bonds4.05 Sept. 15, 2049400 400 First mortgage bonds3.20 March 1, 2050550 550 First mortgage bonds2.70 Jan. 15, 2051375 375 First mortgage bonds (a)4.50 June 1, 2052400 400 First mortgage bonds (b)5.25 April 1, 2053850 - Unamortized discount(41)(37)Unamortized debt issuance cost(59)(53)Current maturities - (250)Total long-term debt$7,450 $6,610 First mortgage bonds (a) First mortgage bonds (a) First mortgage bonds (b) (a)2022 financing. (b)2023 financing. 2023 financing. SPSFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds3.30 %June 15, 2024$150 $150 First mortgage bonds3.30 June 15, 2024200 200 Unsecured senior notes6.00 Oct. 1, 2033100 100 Unsecured senior notes6.00 Oct. 1, 2036250 250 First mortgage bonds4.50 Aug. 15, 2041200 200 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds3.40 Aug. 15, 2046300 300 First mortgage bonds3.70 Aug. 15, 2047450 450 First mortgage bonds4.40 Nov. 15, 2048300 300 First mortgage bonds 3.75 June 15, 2049300 300 First mortgage bonds3.15 May 1, 2050350 350 First mortgage bonds3.15 May 1, 2050250 250 First mortgage bonds (a)5.15 June 1, 2052200 200 First mortgage bonds (b)6.00 Sept. 15, 2053100 - Unamortized discount(10)(10)Unamortized debt issuance cost(29)(29)Current maturities(350) - Total long-term debt$2,961 $3,211 (a)2022 financing.(b)2023 financing.Other SubsidiariesFinancing InstrumentInterest RateMaturity Date20232022Various Eloigne affordable housing project notes0.00% - 8.00%2024 - 2055$27 $27 Current maturities(2)(1)Total long-term debt$25 $26 Maturities of long-term debt:(Millions of Dollars)2024$552 20251,103 2026501 2027501 20281,133 Deferred Financing Costs - Deferred financing costs of approximately $209 million and $193 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2023 and 2022, respectively. Equity through DRIP and Benefits Program - Xcel Energy issued $88 million of equity in 2023 and $84 million of equity in 2022 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.ATM Equity Offering - In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares of common stock were issued (approximately $350 million in net proceeds and $3 million in transaction fees paid). In 2022, 4.30 million shares of common stock were issued (approximately $300 million in net proceeds and $3 million in transaction fees paid). In 2023, 0.90 million shares of common stock were issued ($62 million in net proceeds and $1 million in transaction fees paid). In October 2023, the 2021 ATM offering was closed. SPSFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds3.30 %June 15, 2024$150 $150 First mortgage bonds3.30 June 15, 2024200 200 Unsecured senior notes6.00 Oct. 1, 2033100 100 Unsecured senior notes6.00 Oct. 1, 2036250 250 First mortgage bonds4.50 Aug. 15, 2041200 200 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds3.40 Aug. 15, 2046300 300 First mortgage bonds3.70 Aug. 15, 2047450 450 First mortgage bonds4.40 Nov. 15, 2048300 300 First mortgage bonds 3.75 June 15, 2049300 300 First mortgage bonds3.15 May 1, 2050350 350 First mortgage bonds3.15 May 1, 2050250 250 First mortgage bonds (a)5.15 June 1, 2052200 200 First mortgage bonds (b)6.00 Sept. 15, 2053100 - Unamortized discount(10)(10)Unamortized debt issuance cost(29)(29)Current maturities(350) - Total long-term debt$2,961 $3,211 First mortgage bonds (a) First mortgage bonds (b) (a)2022 financing. 2022 financing. (b)2023 financing. Other SubsidiariesFinancing InstrumentInterest RateMaturity Date20232022Various Eloigne affordable housing project notes0.00% - 8.00%2024 - 2055$27 $27 Current maturities(2)(1)Total long-term debt$25 $26 Maturities of long-term debt: (Millions of Dollars)2024$552 20251,103 2026501 2027501 20281,133 Deferred Financing Costs - Deferred financing costs of approximately $209 million and $193 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2023 and 2022, respectively. Equity through DRIP and Benefits Program - Xcel Energy issued $88 million of equity in 2023 and $84 million of equity in 2022 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock. ATM Equity Offering - In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares of common stock were issued (approximately $350 million in net proceeds and $3 million in transaction fees paid). In 2022, 4.30 million shares of common stock were issued (approximately $300 million in net proceeds and $3 million in transaction fees paid). In 2023, 0.90 million shares of common stock were issued ($62 million in net proceeds and $1 million in transaction fees paid). In October 2023, the 2021 ATM offering was closed. 60 60 60 Table of Contents Table of Contents In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In the fourth quarter, through this ATM Program, Xcel Energy Inc. issued 3.12 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid).Capital Stock - Preferred stock authorized/outstanding:Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2023 and 2022Xcel Energy Inc.7,000,000 $100 - PSCo10,000,000 0.01 - SPS10,000,000 1.00 - Xcel Energy Inc. had the following common stock authorized/outstanding:Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2023Common Stock Outstanding (Shares) as of Dec. 31, 20221,000,000,000 $2.50 554,941,703 549,578,018 Dividend and Other Capital-Related Restrictions - Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.'s utility subsidiaries' dividends are subject to the FERC's jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2023:Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2023NSP-Minnesota47.2 %57.6 %52.3 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.6 (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.(b) Excludes short-term debt.(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,508 $15,702 $16,140 NSP-Wisconsin9 2,520 N/ASPS (a)617 7,298 N/A(a)May not pay a dividend that would cause a loss of its investment grade bond rating. Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. Amounts authorized to issue as of Dec. 31, 2023:(Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota52.8% of total capitalization(a)$2,400 (a)NSP-Wisconsin$625 150 PSCo450 800 SPS100 600 (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. 6. RevenuesRevenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy's operating revenues consisted of the following: Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 - 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 - - 815 Transmission649 - - 649 Other63 156 - 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 - 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 - - 1,354 Transmission675 - - 675 Other97 178 - 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310 In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In the fourth quarter, through this ATM Program, Xcel Energy Inc. issued 3.12 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid).Capital Stock - Preferred stock authorized/outstanding:Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2023 and 2022Xcel Energy Inc.7,000,000 $100 - PSCo10,000,000 0.01 - SPS10,000,000 1.00 - Xcel Energy Inc. had the following common stock authorized/outstanding:Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2023Common Stock Outstanding (Shares) as of Dec. 31, 20221,000,000,000 $2.50 554,941,703 549,578,018 Dividend and Other Capital-Related Restrictions - Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.'s utility subsidiaries' dividends are subject to the FERC's jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2023:Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2023NSP-Minnesota47.2 %57.6 %52.3 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.6 (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.(b) Excludes short-term debt.(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,508 $15,702 $16,140 NSP-Wisconsin9 2,520 N/ASPS (a)617 7,298 N/A(a)May not pay a dividend that would cause a loss of its investment grade bond rating. Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In the fourth quarter, through this ATM Program, Xcel Energy Inc. issued 3.12 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). Capital Stock - Preferred stock authorized/outstanding: Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2023 and 2022Xcel Energy Inc.7,000,000 $100 - PSCo10,000,000 0.01 - SPS10,000,000 1.00 - Xcel Energy Inc. had the following common stock authorized/outstanding: --- ## Modified: Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation. **Key changes:** - Removed sentence: "Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows." - Removed sentence: "Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment." - Removed sentence: "Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year." - Removed sentence: "The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction." - Removed sentence: "Thus, the rates a utility is allowed to charge may or may not match its costs at any given time." **Prior (2023):** NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include: •Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal. •Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor. •Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change. The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota's nuclear operations. Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on common stock. The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota's nuclear operations. Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses. If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs. **Current (2024):** NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include: •Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal. •Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor. •Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change. The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota's nuclear operations. Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses. If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs. --- ## Modified: Station, Location and Unit at Dec. 31, 2023 **Key changes:** - Reworded sentence: "MW (a) (b) (c) (d) (e) (e) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (f) (e) (e) (e) (e) (e) Northern Wind-Murray County, MN, 37 Units (g) (e) (e) (e) (a)Summer 2023 net dependable capacity." - Reworded sentence: "31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec." - Reworded sentence: "31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551" **Prior (2023):** MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) (d) Nobles-Nobles County, MN, 133 Units (e) (d) (d) (d) (a)Summer 2022 net dependable capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)Refuse-derived fuel is made from municipal solid waste. (d)Capacity is attainable only when wind conditions are sufficiently available. (e)Repowered in 2022. NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 (a)Summer 2022 net dependable capacity.(b)Refuse-derived fuel is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975335 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 Manchief, CO, 2 Units (e)Natural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 Various locations, 8 UnitsNatural GasVarious251 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Total6,151 (a)Summer 2022 net dependable capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Purchased in 2022. (f)Capacity is attainable only when wind conditions are sufficiently available. NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 **Current (2024):** MW (a) (b) (c) (d) (e) (e) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (f) (e) (e) (e) (e) (e) Northern Wind-Murray County, MN, 37 Units (g) (e) (e) (e) (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023. (c)Based on NSP-Minnesota's ownership of 59%. (d)RDF is made from municipal solid waste. (e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota's wind facilities had a weighted-average capacity factors of 43%. (f)Repowered in 2023. (g)Purchased in 2023. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo's wind facilities had a weighted-average capacity factors of 43%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 --- ## Modified: Statement of Income Analysis **Key changes:** - Reworded sentence: "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." - Reworded sentence: "Percentage increase (decrease) in normal and actual HDD, CDD and THI:2023 vs.Normal2022 vs.Normal2023 vs." - Reworded sentence: "Percentage increase (decrease) in normal and actual HDD, CDD and THI: 2023 vs.Normal2022 vs.Normal2023 vs." - Reworded sentence: "•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." - Reworded sentence: "In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.Electric Revenues, Fuel and Purchased Power and Electric Margin(Millions of Dollars)20232022Electric revenues$11,446 $12,123 Electric fuel and purchased power(4,278)(5,005)Electric margin$7,168 $7,118 2023 vs." **Prior (2023):** The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income. Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. 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. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather.Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2022 vs.Normal2021 vs.Normal2022 vs. 2021HDD6.5 %(6.6)%13.0 %CDD23.7 12.2 16.1 THI5.6 26.8 (15.8)Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2022 vs. Normal2021 vs. Normal2022 vs. 2021Retail electric$0.138 $0.096 $0.042 Decoupling and sales true-up(0.061)(0.066)0.005 Electric total$0.077 $0.030 $0.047 Firm natural gas0.037 (0.025)0.062 Total$0.114 $0.005 $0.109 Sales - Sales growth (decline) for actual and weather-normalized sales:2022 vs. 2021PSCoNSP-MinnesotaSPSNSP-WisconsinXcel EnergyActualElectric residential(1.5)%(1.2)%6.5 %1.1 %(0.1)%Electric C&I - 1.7 8.9 3.3 3.3 Total retail electric sales(0.5)0.8 8.4 2.6 2.3 Firm natural gas sales5.4 18.3 N/A17.3 10.1 2022 vs. 2021PSCoNSP-MinnesotaSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(3.6)%(0.2)%0.8 % - %(1.3)%Electric C&I(0.3)2.1 8.4 3.4 3.2 Total retail electric sales(1.4)1.3 6.9 2.4 1.8 Firm natural gas sales(3.1)5.5 N/A5.8 0.1 In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather. Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI: 2022 vs.Normal2021 vs.Normal2022 vs. 2021HDD6.5 %(6.6)%13.0 %CDD23.7 12.2 16.1 THI5.6 26.8 (15.8) Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2022 vs. Normal2021 vs. Normal2022 vs. 2021Retail electric$0.138 $0.096 $0.042 Decoupling and sales true-up(0.061)(0.066)0.005 Electric total$0.077 $0.030 $0.047 Firm natural gas0.037 (0.025)0.062 Total$0.114 $0.005 $0.109 Sales - Sales growth (decline) for actual and weather-normalized sales: 2022 vs. 2021PSCoNSP-MinnesotaSPSNSP-WisconsinXcel EnergyActualElectric residential(1.5)%(1.2)%6.5 %1.1 %(0.1)%Electric C&I - 1.7 8.9 3.3 3.3 Total retail electric sales(0.5)0.8 8.4 2.6 2.3 Firm natural gas sales5.4 18.3 N/A17.3 10.1 2022 vs. 2021PSCoNSP-MinnesotaSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(3.6)%(0.2)%0.8 % - %(1.3)%Electric C&I(0.3)2.1 8.4 3.4 3.2 Total retail electric sales(1.4)1.3 6.9 2.4 1.8 Firm natural gas sales(3.1)5.5 N/A5.8 0.1 27 27 27 Table of Contents Table of Contents 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. 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. Electric MarginElectric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. These price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.Electric Revenues, Fuel and Purchased Power and Electric Margin(Millions of Dollars)20222021Electric revenues$12,123 $11,205 Electric fuel and purchased power(5,005)(4,733)Electric margin$7,118 $6,472 Change in Electric Margin(Millions of Dollars)2022 vs. 2021Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin)$506 Revenue recognition for the Texas rate case surcharge (a)85 Sales and demand (b)80 Non-fuel riders64 Wholesale transmission (net)50 Estimated impact of weather (net of decoupling/sales true-up)33 PTCs flowed back to customers (offset by lower ETR)(150)Other (net)(22)Total increase$646 (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.Natural Gas MarginNatural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms. Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin(Millions of Dollars)20222021Natural gas revenues$3,080 $2,132 Cost of natural gas sold and transported(1,910)(1,081)Natural gas margin$1,170 $1,051 Change in Natural Gas Margin(Millions of Dollars)2022 vs. 2021Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, North Dakota)$61 Estimated impact of weather46 Conservation revenue (offset in expenses)13 Infrastructure and integrity riders9 Winter Storm Uri disallowances(20)Other (net)10 Total increase$119 Non-Fuel Operating Expenses and Other ItemsO&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; and other. 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. 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. Electric MarginElectric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. These price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.Electric Revenues, Fuel and Purchased Power and Electric Margin(Millions of Dollars)20222021Electric revenues$12,123 $11,205 Electric fuel and purchased power(5,005)(4,733)Electric margin$7,118 $6,472 **Current (2024):** The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income. Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy's financial performance. However, electric decoupling mechanisms in Colorado (mechanism expired in September 2023) and electric sales true-up mechanisms in Minnesota and gas decoupling mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in those jurisdictions. 27 27 27 Table of Contents Table of Contents Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity.HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather.Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2023 vs.Normal2022 vs.Normal2023 vs. 2022HDD(7.3)%6.5 %(12.9)%CDD5.2 23.7 (13.8)THI16.0 5.6 9 Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2023 vs. Normal2022 vs. Normal2023 vs. 2022Retail electric$0.013 $0.138 $(0.125)Decoupling and sales true-up(0.007)(0.061)0.054 Electric total$0.006 $0.077 $(0.071)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:2023 vs. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(0.5)%(4.0)%(3.0)%(2.6)%(2.3)%Electric C&I(1.1)(1.9)5.2 (0.5)0.5 Total retail electric sales(0.9)(2.6)3.6 (1.1)(0.3)Firm natural gas sales(12.0)(1.5)N/A(12.6)(5.7)2023 vs. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.0 %1.6 %1.1 %0.1 %1.2 %Electric C&I(1.1)(0.4)5.3 (0.4)1.0 Total retail electric sales(0.4)0.3 4.5 (0.3)1.0 Firm natural gas sales - 2.3 N/A(0.4)1.4 Annual weather-normalized electric sales growth (decline)•NSP-Minnesota - Residential sales increased due to a 1.2% increase in customers outpacing declines in use per customer. The decline in C&I sales was due to lower use per customer, particularly due to weakness in the manufacturing sector compared to prior year.•PSCo - Residential sales increased due to increased use per customer and a 1.3% increase in customers. The decline in C&I sales was attributable to decreased use per customer, primarily in the manufacturing sector. •SPS - Residential sales growth was primarily attributable to a 0.7% increase in customers and increased use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector. •NSP-Wisconsin - The C&I sales decline was associated with lower use per customer, experienced primarily in the transportation and manufacturing sectors.Annual weather-normalized natural gas sales growth (decline)•Natural gas sales reflect 1.2% residential and 0.7% C&I customer growth and an increase in C&I use per customer at PSCo. Partially offsetting these increases were lower use per residential customer in all jurisdictions. Electric MarginElectric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. These price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.Electric Revenues, Fuel and Purchased Power and Electric Margin(Millions of Dollars)20232022Electric revenues$11,446 $12,123 Electric fuel and purchased power(4,278)(5,005)Electric margin$7,168 $7,118 Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity.HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather.Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2023 vs.Normal2022 vs.Normal2023 vs. 2022HDD(7.3)%6.5 %(12.9)%CDD5.2 23.7 (13.8)THI16.0 5.6 9 Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2023 vs. Normal2022 vs. Normal2023 vs. 2022Retail electric$0.013 $0.138 $(0.125)Decoupling and sales true-up(0.007)(0.061)0.054 Electric total$0.006 $0.077 $(0.071)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:2023 vs. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(0.5)%(4.0)%(3.0)%(2.6)%(2.3)%Electric C&I(1.1)(1.9)5.2 (0.5)0.5 Total retail electric sales(0.9)(2.6)3.6 (1.1)(0.3)Firm natural gas sales(12.0)(1.5)N/A(12.6)(5.7) Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather. Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI: 2023 vs.Normal2022 vs.Normal2023 vs. 2022HDD(7.3)%6.5 %(12.9)%CDD5.2 23.7 (13.8)THI16.0 5.6 9 Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2023 vs. Normal2022 vs. Normal2023 vs. 2022Retail electric$0.013 $0.138 $(0.125)Decoupling and sales true-up(0.007)(0.061)0.054 Electric total$0.006 $0.077 $(0.071)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: 2023 vs. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(0.5)%(4.0)%(3.0)%(2.6)%(2.3)%Electric C&I(1.1)(1.9)5.2 (0.5)0.5 Total retail electric sales(0.9)(2.6)3.6 (1.1)(0.3)Firm natural gas sales(12.0)(1.5)N/A(12.6)(5.7) 2023 vs. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.0 %1.6 %1.1 %0.1 %1.2 %Electric C&I(1.1)(0.4)5.3 (0.4)1.0 Total retail electric sales(0.4)0.3 4.5 (0.3)1.0 Firm natural gas sales - 2.3 N/A(0.4)1.4 Annual weather-normalized electric sales growth (decline)•NSP-Minnesota - Residential sales increased due to a 1.2% increase in customers outpacing declines in use per customer. The decline in C&I sales was due to lower use per customer, particularly due to weakness in the manufacturing sector compared to prior year.•PSCo - Residential sales increased due to increased use per customer and a 1.3% increase in customers. The decline in C&I sales was attributable to decreased use per customer, primarily in the manufacturing sector. •SPS - Residential sales growth was primarily attributable to a 0.7% increase in customers and increased use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector. •NSP-Wisconsin - The C&I sales decline was associated with lower use per customer, experienced primarily in the transportation and manufacturing sectors.Annual weather-normalized natural gas sales growth (decline)•Natural gas sales reflect 1.2% residential and 0.7% C&I customer growth and an increase in C&I use per customer at PSCo. Partially offsetting these increases were lower use per residential customer in all jurisdictions. Electric MarginElectric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. These price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.Electric Revenues, Fuel and Purchased Power and Electric Margin(Millions of Dollars)20232022Electric revenues$11,446 $12,123 Electric fuel and purchased power(4,278)(5,005)Electric margin$7,168 $7,118 2023 vs. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.0 %1.6 %1.1 %0.1 %1.2 %Electric C&I(1.1)(0.4)5.3 (0.4)1.0 Total retail electric sales(0.4)0.3 4.5 (0.3)1.0 Firm natural gas sales - 2.3 N/A(0.4)1.4 --- ## Modified: Material Cash Requirements and Other Commitments **Key changes:** - Reworded sentence: "31, 2023)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$43,659 $1,567 $3,631 $3,564 $34,897 Finance lease obligations218 10 19 16 173 Operating leases obligations (a)1,520 277 509 313 421 Unconditional purchase obligations (b) (c)4,022 1,429 1,267 686 640 Other long-term obligations, including current portion (d)57 18 27 12 - Other short-term obligations591 591 - - - Short-term debt785 785 - - - Total contractual cash obligations$50,852 $4,677 $5,453 $4,591 $36,131 Operating leases obligations (a) Unconditional purchase obligations (b) (c) Other long-term obligations, including current portion (d) (a)Included in operating lease obligations are $244 million, $461 million, $269 million and $259 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases." - Reworded sentence: "(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." - Reworded sentence: "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." - Reworded sentence: "Xcel Energy's capital expenditure forecast is subject to continuing review and modification." - Reworded sentence: "31, 2022Fair value of pension assets$2,690 $2,685 Projected pension obligation (a)2,943 2,871 Funded status$(253)$(186)(a)Excludes non-qualified plan of $12 million and $11 million at Dec." **Prior (2023):** Payments Due by Period (as of Dec. 31, 2022)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$39,750 $2,059 $3,492 $2,714 $31,485 Finance lease obligations228 10 20 17 181 Operating leases obligations (a)1,457 264 506 287 400 Unconditional purchase obligations (b)5,129 1,899 1,475 921 834 Other long-term obligations, including current portion (c)111 53 35 23 - Other short-term obligations436 436 - - - Short-term debt813 813 - - - Total contractual cash obligations$47,924 $5,534 $5,528 $3,962 $32,900 Operating leases obligations (a) Unconditional purchase obligations (b) Other long-term obligations, including current portion (c) (a)Included in operating lease obligations are $231 million, $455 million, $251 million and $326 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases. (b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms. (c)Primarily consists of contracts for information technology services. Capital Expenditures - Base capital expenditures and incremental capital forecasts: Actual Base Capital Forecast (Millions of Dollars)By Regulated Utility2022202320242025202620272023 - 2027 TotalPSCo$1,940 $2,140 $2,440 $2,550 $1,980 $2,190 $11,300 NSP-Minnesota1,980 2,000 2,400 2,530 2,200 2,580 11,710 SPS610 710 780 720 770 900 3,880 NSP-Wisconsin370 540 570 500 450 540 2,600 Other (a)(10)10 10 (30)10 10 10 Total base capital expenditures$4,890 $5,400 $6,200 $6,270 $5,410 $6,220 $29,500 Other (a) (a) Other category includes intercompany transfers for safe harbor wind turbines. ActualBase Capital Forecast (Millions of Dollars)By Function2022202320242025202620272023 - 2027 TotalElectric distribution$1,370 $1,610 $1,790 $1,680 $2,000 $2,450 $9,530 Electric transmission960 1,280 1,650 1,890 1,690 1,900 8,410 Electric generation720 710 910 900 560 650 3,730 Natural gas730 740 730 760 650 680 3,560 Other700 780 840 570 510 540 3,240 Renewables410 280 280 470 - - 1,030 Total base capital expenditures$4,890 $5,400 $6,200 $6,270 $5,410 $6,220 $29,500 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.Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Financing for Capital Expenditures through 2027 - 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. 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 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. Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Financing for Capital Expenditures through 2027 - 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. Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Financing for Capital Expenditures through 2027 - 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. 42 42 42 Table of Contents Table of Contents Current estimated financing plans of Xcel Energy for 2023 through 2027:(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$20,540 New debt (b)8,210 Equity through the DRIP and benefit program425 Other equity325 Base capital expenditures 2023 - 2027$29,500 Maturing Debt$3,800 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2023, Xcel Energy announced an increase in the annual dividend of 13 cents per share, which represents an increase of 6.7%.Xcel Energy's dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy's capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2022Dec. 31, 2021Fair value of pension assets$2,685 $3,670 Projected pension obligation (a)2,871 3,718 Funded status$(186)$(48)(a)Excludes non-qualified plan of $11 million and $43 million at Dec. 31, 2022 and 2021, respectively.Pension Assumptions20222021Discount rate5.80 %3.08 %Expected long-term rate of return6.93 6.49 Capital SourcesShort-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. As of Feb. 22, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $328 $1,172 $6 $1,178 PSCo700 123 577 5 582 NSP-Minnesota700 186 514 6 520 SPS500 91 409 2 411 NSP-Wisconsin150 29 121 2 123 Total$3,550 $757 $2,793 $21 $2,814 (a)Credit facilities expire in September 2027.(b)Includes outstanding commercial paper and letters of credit.Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2022 and 2021, Xcel Energy had approximately 550 million shares and 544 million shares of common stock outstanding, respectively. 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. Current estimated financing plans of Xcel Energy for 2023 through 2027:(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$20,540 New debt (b)8,210 Equity through the DRIP and benefit program425 Other equity325 Base capital expenditures 2023 - 2027$29,500 Maturing Debt$3,800 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2023, Xcel Energy announced an increase in the annual dividend of 13 cents per share, which represents an increase of 6.7%.Xcel Energy's dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy's capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2022Dec. 31, 2021Fair value of pension assets$2,685 $3,670 Projected pension obligation (a)2,871 3,718 Funded status$(186)$(48)(a)Excludes non-qualified plan of $11 million and $43 million at Dec. 31, 2022 and 2021, respectively.Pension Assumptions20222021Discount rate5.80 %3.08 %Expected long-term rate of return6.93 6.49 Current estimated financing plans of Xcel Energy for 2023 through 2027:(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$20,540 New debt (b)8,210 Equity through the DRIP and benefit program425 Other equity325 Base capital expenditures 2023 - 2027$29,500 Maturing Debt$3,800 Cash from operations (a) New debt (b) (a)Net of dividends and pension funding. (b)Reflects a combination of short and long-term debt; net of refinancing. **Current (2024):** Payments Due by Period (as of Dec. 31, 2023)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$43,659 $1,567 $3,631 $3,564 $34,897 Finance lease obligations218 10 19 16 173 Operating leases obligations (a)1,520 277 509 313 421 Unconditional purchase obligations (b) (c)4,022 1,429 1,267 686 640 Other long-term obligations, including current portion (d)57 18 27 12 - Other short-term obligations591 591 - - - Short-term debt785 785 - - - Total contractual cash obligations$50,852 $4,677 $5,453 $4,591 $36,131 Operating leases obligations (a) Unconditional purchase obligations (b) (c) Other long-term obligations, including current portion (d) (a)Included in operating lease obligations are $244 million, $461 million, $269 million and $259 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases. (b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms. (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: Actual Base Capital Forecast (Millions of Dollars)By Regulated Utility2023202420252026202720282024 - 2028 TotalPSCo$2,310 $3,300 $5,230 $4,320 $3,620 $2,730 $19,200 NSP-Minnesota2,370 2,660 2,970 2,380 2,500 2,540 13,050 SPS750 910 780 660 870 830 4,050 NSP-Wisconsin450 570 600 570 600 650 2,990 Other (a)330 (20)(300)10 10 10 (290)Total base capital expenditures$6,210 $7,420 $9,280 $7,940 $7,600 $6,760 $39,000 Other (a) (a)Other category includes intercompany transfers for safe harbor wind turbines. ActualBase Capital Forecast (Millions of Dollars)By Function2023202420252026202720282024 - 2028 TotalElectric transmission$1,320 $1,710 $2,020 $2,450 $2,850 $2,470 $11,500 Electric distribution1,730 1,770 1,960 2,200 2,200 2,470 10,600 Renewables350 1,500 2,910 940 240 20 5,610 Electric generation780 940 1,290 1,050 1,060 600 4,940 Natural gas780 740 680 630 620 570 3,240 Other1,250 760 420 670 630 630 3,110 Total base capital expenditures$6,210 $7,420 $9,280 $7,940 $7,600 $6,760 $39,000 The base plan does not include potential renewable generation additions at the NSP System, SPS and PSCo, which could result in additional capital expenditures of approximately $5 billion. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt. Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. 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. 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. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. 41 41 41 Table of Contents Table of Contents 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 2024 through 2028 (includes the impact of tax credit transferability):(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$22,000 New debt (b)13,000 Equity through the DRIP and benefit program500 Other equity3,500 Base capital expenditures 2024 - 2028$39,000 Maturing Debt$3,780 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2024, Xcel Energy announced an increase in the annual dividend of 11 cents per share, which represents an increase of 5.3%.Xcel Energy's dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy's capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2023Dec. 31, 2022Fair value of pension assets$2,690 $2,685 Projected pension obligation (a)2,943 2,871 Funded status$(253)$(186)(a)Excludes non-qualified plan of $12 million and $11 million at Dec. 31, 2023 and 2022, respectively.Pension Assumptions20232022Discount rate5.49 %5.80 %Expected long-term rate of return6.93 6.93 Capital SourcesShort-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. As of Feb. 20, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $486 $1,014 $2 $1,016 PSCo700 258 442 6 448 NSP-Minnesota700 273 427 10 437 SPS500 99 401 3 404 NSP-Wisconsin150 43 107 8 115 Total$3,550 $1,159 $2,391 $29 $2,420 (a)Credit facilities expire in September 2027.(b)Includes outstanding commercial paper and letters of credit.Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2023 and 2022, Xcel Energy had approximately 555 million shares and 550 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval. 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 2024 through 2028 (includes the impact of tax credit transferability):(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$22,000 New debt (b)13,000 Equity through the DRIP and benefit program500 Other equity3,500 Base capital expenditures 2024 - 2028$39,000 Maturing Debt$3,780 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2024, Xcel Energy announced an increase in the annual dividend of 11 cents per share, which represents an increase of 5.3%.Xcel Energy's dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy's capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2023Dec. 31, 2022Fair value of pension assets$2,690 $2,685 Projected pension obligation (a)2,943 2,871 Funded status$(253)$(186)(a)Excludes non-qualified plan of $12 million and $11 million at Dec. 31, 2023 and 2022, respectively. 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 2024 through 2028 (includes the impact of tax credit transferability): (Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$22,000 New debt (b)13,000 Equity through the DRIP and benefit program500 Other equity3,500 Base capital expenditures 2024 - 2028$39,000 Maturing Debt$3,780 Cash from operations (a) New debt (b) (a)Net of dividends and pension funding. (b)Reflects a combination of short and long-term debt; net of refinancing. --- ## Modified: Purchased Power Arrangements and Transmission Service Providers **Key changes:** - Reworded sentence: "Purchased Transmission Services - SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.Natural GasSPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines." - Reworded sentence: "Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.OtherSupply Chain 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." - Reworded sentence: "Purchased Transmission Services - SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers." **Prior (2023):** SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements. Purchased Power - SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services - SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers. Natural GasSPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA, DOT and PUCT for pipeline safety compliance.Wholesale and Commodity Marketing OperationsSPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.OtherSupply Chain 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. 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 TransformersThe 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.Solar ResourcesIn 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%. 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 WildfireIn 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 investigating 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. **Current (2024):** SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements. Purchased Power - SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services - SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.Natural GasSPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA, DOT and PUCT for pipeline safety compliance.Wholesale and Commodity Marketing OperationsSPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.OtherSupply Chain Xcel Energy's ability to meet customer energy requirements, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. Inflationary pressures, labor shortages, and the impact of geopolitical events have further exacerbated these disruptions. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.Additionally, certain products, components, and equipment, particularly in renewables categories, originate in countries that could face tariffs, fines, or restrictions from government or other regulatory bodies and present a cost and supply risk until there is sufficient capacity and supply base with adequate capacity to meet US needs.Electric Meters and TransformersSupply 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 ResourcesIn 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. Purchased Transmission Services - SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers. --- ## Modified: Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather. **Key changes:** - Reworded sentence: "Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance." - Reworded sentence: "Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties." - Reworded sentence: "If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows." - Removed sentence: "We may be subject to climate change lawsuits." - Removed sentence: "An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages." **Prior (2023):** The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties. In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency's Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. **Current (2024):** Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows. Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency's Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. --- ## Modified: Joint Ownership of Generation, Transmission and Gas Facilities **Key changes:** - Reworded sentence: "31, 2023: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 Total NSP-Minnesota (a) (a)Projects additionally include $2 million in CWIP." - Reworded sentence: "(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $108 76 %Hayden Unit 2151 87 37 Hayden common facilities44 31 53 Craig Units 1 and 282 55 10 Craig common facilities39 25 7 Comanche Unit 3916 191 67 Comanche common facilities29 4 77 Electric transmission:Transmission and other facilities189 75 VariousGas transmission:Rifle, CO to Avon, CO28 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,643 $587 Total PSCo (a) (a)Projects additionally include $18 million in CWIP." - Reworded sentence: "56 56 56 Table of Contents Table of Contents" **Prior (2023):** The utility subsidiaries' jointly owned assets as of Dec. 31, 2022: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$623 $468 59 %Sherco common facilities180 115 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 3 50 Huntley Wilmarth49 1 50 CapX2020818 124 51 Total NSP-Minnesota (a)$1,686 $715 Total NSP-Minnesota (a) (a)Projects additionally include $4 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$177 $20 37 %CapX2020166 34 80 Total NSP-Wisconsin (a)$343 $54 Total NSP-Wisconsin (a) (a)Projects additionally include $1 million in CWIP. 56 56 56 Table of Contents Table of Contents (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $99 76 %Hayden Unit 2151 81 37 Hayden common facilities42 29 53 Craig Units 1 and 282 51 10 Craig common facilities39 24 7 Comanche Unit 3918 174 67 Comanche common facilities28 3 82 Electric transmission:Transmission and other facilities186 72 VariousGas transmission:Rifle, CO to Avon, CO25 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,636 $544 (a)Projects additionally include $10 million in CWIP.Each company's share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $99 76 %Hayden Unit 2151 81 37 Hayden common facilities42 29 53 Craig Units 1 and 282 51 10 Craig common facilities39 24 7 Comanche Unit 3918 174 67 Comanche common facilities28 3 82 Electric transmission:Transmission and other facilities186 72 VariousGas transmission:Rifle, CO to Avon, CO25 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,636 $544 (a)Projects additionally include $10 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $99 76 %Hayden Unit 2151 81 37 Hayden common facilities42 29 53 Craig Units 1 and 282 51 10 Craig common facilities39 24 7 Comanche Unit 3918 174 67 Comanche common facilities28 3 82 Electric transmission:Transmission and other facilities186 72 VariousGas transmission:Rifle, CO to Avon, CO25 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,636 $544 Total PSCo (a) (a)Projects additionally include $10 million in CWIP. Each company's share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. Each company's share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. **Current (2024):** The utility subsidiaries' jointly owned assets as of Dec. 31, 2023: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 Total NSP-Minnesota (a) (a)Projects additionally include $2 million in CWIP. Projects additionally include $2 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$178 $25 37 %CapX2020169 39 80 Total NSP-Wisconsin (a)$347 $64 Total NSP-Wisconsin (a) (a)Projects additionally include $1 million in CWIP. Projects additionally include $1 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $108 76 %Hayden Unit 2151 87 37 Hayden common facilities44 31 53 Craig Units 1 and 282 55 10 Craig common facilities39 25 7 Comanche Unit 3916 191 67 Comanche common facilities29 4 77 Electric transmission:Transmission and other facilities189 75 VariousGas transmission:Rifle, CO to Avon, CO28 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,643 $587 (a)Projects additionally include $18 million in CWIP.Each company's share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $108 76 %Hayden Unit 2151 87 37 Hayden common facilities44 31 53 Craig Units 1 and 282 55 10 Craig common facilities39 25 7 Comanche Unit 3916 191 67 Comanche common facilities29 4 77 Electric transmission:Transmission and other facilities189 75 VariousGas transmission:Rifle, CO to Avon, CO28 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,643 $587 Total PSCo (a) (a)Projects additionally include $18 million in CWIP. Projects additionally include $18 million in CWIP. Each company's share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. 56 56 56 Table of Contents Table of Contents --- ## Modified: Annual weather-normalized electric sales growth (decline) **Key changes:** - Reworded sentence: "•NSP-Minnesota - Residential sales increased due to a 1.2% increase in customers outpacing declines in use per customer." - Reworded sentence: "•NSP-Wisconsin - The C&I sales decline was associated with lower use per customer, experienced primarily in the transportation and manufacturing sectors." **Prior (2023):** •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. 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. **Current (2024):** •NSP-Minnesota - Residential sales increased due to a 1.2% increase in customers outpacing declines in use per customer. The decline in C&I sales was due to lower use per customer, particularly due to weakness in the manufacturing sector compared to prior year. •PSCo - Residential sales increased due to increased use per customer and a 1.3% increase in customers. The decline in C&I sales was attributable to decreased use per customer, primarily in the manufacturing sector. •SPS - Residential sales growth was primarily attributable to a 0.7% increase in customers and increased use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector. •NSP-Wisconsin - The C&I sales decline was associated with lower use per customer, experienced primarily in the transportation and manufacturing sectors. --- ## Modified: Capital Sources **Key changes:** - Reworded sentence: "20, 2024, Xcel Energy Inc." - Reworded sentence: "31, 2023 and 2022, Xcel Energy had approximately 555 million shares and 550 million shares of common stock outstanding, respectively." - Reworded sentence: "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 2023 actual ongoing earnings base of $3.35 per share.• Deliver annual dividend increases of 5% to 7%.• Target a dividend payout ratio of 50% to 60%.• Maintain senior secured debt credit ratings in the A range.ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information." - Reworded sentence: "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." **Prior (2023):** Short-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments. Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are: •$1.50 billion for Xcel Energy Inc. •$700 million for PSCo. •$700 million for NSP-Minnesota. •$500 million for SPS. •$150 million for NSP-Wisconsin. See Note 5 to the consolidated financial statements for further information. Credit Facility Agreements - Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. As of Feb. 22, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs: (Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $328 $1,172 $6 $1,178 PSCo700 123 577 5 582 NSP-Minnesota700 186 514 6 520 SPS500 91 409 2 411 NSP-Wisconsin150 29 121 2 123 Total$3,550 $757 $2,793 $21 $2,814 Facility (a) Drawn (b) (a)Credit facilities expire in September 2027. (b)Includes outstanding commercial paper and letters of credit. Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2022 and 2021, Xcel Energy had approximately 550 million shares and 544 million shares of common stock outstanding, respectively. 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. 43 43 43 Table of Contents Table of Contents Planned Financing Activity - Xcel Energy's 2023 financing plans reflect the following:(Millions of Dollars)SecurityAmountAnticipated TimingXcel Energy Inc.Senior Unsecured Bonds$500 Third QuarterPSCoFirst Mortgage Bonds700Second QuarterSPSFirst Mortgage Bonds100Third QuarterNSP-MinnesotaFirst Mortgage Bonds750Second QuarterNSP-WisconsinFirst Mortgage Bonds125Second QuarterLong-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. See Note 5 to the consolidated financial statements for further information.Earnings Guidance and Long-Term EPS and Dividend Growth Rate ObjectivesXcel Energy 2023 Earnings Guidance - Xcel Energy's 2023 GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per share.(a)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%.•Capital rider revenue is projected to increase $90 million to $100 million (net of PTCs). •O&M expenses are projected to decline ~2%.•Depreciation expense is projected to increase approximately $130 million to $140 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.•AFUDC - equity is projected to increase $0 million to $10 million.•ETR is projected to be ~(5%) to (7%). (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.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 annual dividend increases of 5% to 7%.• Target a dividend payout ratio of 60% to 70%.• Maintain senior secured debt credit ratings in the A range.ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. Planned Financing Activity - Xcel Energy's 2023 financing plans reflect the following:(Millions of Dollars)SecurityAmountAnticipated TimingXcel Energy Inc.Senior Unsecured Bonds$500 Third QuarterPSCoFirst Mortgage Bonds700Second QuarterSPSFirst Mortgage Bonds100Third QuarterNSP-MinnesotaFirst Mortgage Bonds750Second QuarterNSP-WisconsinFirst Mortgage Bonds125Second QuarterLong-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. See Note 5 to the consolidated financial statements for further information.Earnings Guidance and Long-Term EPS and Dividend Growth Rate ObjectivesXcel Energy 2023 Earnings Guidance - Xcel Energy's 2023 GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per share.(a)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%.•Capital rider revenue is projected to increase $90 million to $100 million (net of PTCs). •O&M expenses are projected to decline ~2%.•Depreciation expense is projected to increase approximately $130 million to $140 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.•AFUDC - equity is projected to increase $0 million to $10 million.•ETR is projected to be ~(5%) to (7%). (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.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 annual dividend increases of 5% to 7%.• Target a dividend payout ratio of 60% to 70%.• Maintain senior secured debt credit ratings in the A range. Planned Financing Activity - Xcel Energy's 2023 financing plans reflect the following: (Millions of Dollars)SecurityAmountAnticipated TimingXcel Energy Inc.Senior Unsecured Bonds$500 Third QuarterPSCoFirst Mortgage Bonds700Second QuarterSPSFirst Mortgage Bonds100Third QuarterNSP-MinnesotaFirst Mortgage Bonds750Second QuarterNSP-WisconsinFirst Mortgage Bonds125Second 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. See Note 5 to the consolidated financial statements for further information. **Current (2024):** Short-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments. Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are: •$1.50 billion for Xcel Energy Inc. •$700 million for PSCo. •$700 million for NSP-Minnesota. •$500 million for SPS. •$150 million for NSP-Wisconsin. See Note 5 to the consolidated financial statements for further information. Credit Facility Agreements - Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. As of Feb. 20, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs: (Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $486 $1,014 $2 $1,016 PSCo700 258 442 6 448 NSP-Minnesota700 273 427 10 437 SPS500 99 401 3 404 NSP-Wisconsin150 43 107 8 115 Total$3,550 $1,159 $2,391 $29 $2,420 Facility (a) Drawn (b) (a)Credit facilities expire in September 2027. (b)Includes outstanding commercial paper and letters of credit. Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2023 and 2022, Xcel Energy had approximately 555 million shares and 550 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval. 42 42 42 Table of Contents Table of Contents Planned Financing Activity - Xcel Energy's 2024 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Anticipated TimingExpected TenorXcel Energy Inc.Senior Unsecured Notes$900 First Quarter10 YearPSCoFirst Mortgage Bonds1,200 Second Quarter10 Year and 30 YearNSP-MinnesotaFirst Mortgage Bonds700First Quarter30 YearSPSFirst Mortgage Bonds550Second Quarter30 YearNSP-WisconsinFirst Mortgage Bonds400Second Quarter30 YearLong-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 ObjectivesXcel Energy 2024 Earnings Guidance - Xcel Energy's 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.(a)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 increase 1% to 2%.•Depreciation expense is projected to increase approximately $250 million to $260 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. 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 2023 actual ongoing earnings base of $3.35 per share.• Deliver annual dividend increases of 5% to 7%.• Target a dividend payout ratio of 50% to 60%.• Maintain senior secured debt credit ratings in the A range.ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. Planned Financing Activity - Xcel Energy's 2024 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Anticipated TimingExpected TenorXcel Energy Inc.Senior Unsecured Notes$900 First Quarter10 YearPSCoFirst Mortgage Bonds1,200 Second Quarter10 Year and 30 YearNSP-MinnesotaFirst Mortgage Bonds700First Quarter30 YearSPSFirst Mortgage Bonds550Second Quarter30 YearNSP-WisconsinFirst Mortgage Bonds400Second Quarter30 YearLong-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 ObjectivesXcel Energy 2024 Earnings Guidance - Xcel Energy's 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.(a)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 increase 1% to 2%.•Depreciation expense is projected to increase approximately $250 million to $260 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. 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. Planned Financing Activity - Xcel Energy's 2024 financing plans reflect the following: IssuerSecurityAmount (Millions of Dollars)Anticipated TimingExpected TenorXcel Energy Inc.Senior Unsecured Notes$900 First Quarter10 YearPSCoFirst Mortgage Bonds1,200 Second Quarter10 Year and 30 YearNSP-MinnesotaFirst Mortgage Bonds700First Quarter30 YearSPSFirst Mortgage Bonds550Second Quarter30 YearNSP-WisconsinFirst Mortgage Bonds400Second Quarter30 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. --- ## Modified: CONSOLIDATED STATEMENTS OF CASH FLOWS **Key changes:** - Reworded sentence: "31 202320222021Operating activities Net income$1,771 $1,736 $1,597 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,471 2,436 2,143 Nuclear fuel amortization96 118 114 Deferred income taxes(59)(140)(79)Allowance for equity funds used during construction(91)(75)(73)Earnings from equity method investments(35)(36)(62)Dividends from equity method investments35 37 42 Provision for bad debts79 73 60 Share-based compensation expense25 20 31 Changes in operating assets and liabilities:Accounts receivable(27)(429)(164)Accrued unbilled revenues252 (243)(149)Inventories(98)(203)(126)Other current assets86 (58)(34)Accounts payable(149)195 138 Net regulatory assets and liabilities911 570 (973)Other current liabilities200 102 (1)Pension and other employee benefit obligations17 (49)(135)Other, net(157)(122)(140)Net cash provided by operating activities5,327 3,932 2,189 Investing activitiesCapital/construction expenditures(5,854)(4,638)(4,244)Purchase of investment securities(994)(1,332)(757)Proceeds from the sale of investment securities959 1,297 743 Other, net(37)20 (29)Net cash used in investing activities(5,926)(4,653)(4,287)Financing activities(Repayments of) proceeds from short-term borrowings, net(28)(192)421 Proceeds from issuances of long-term debt2,630 2,164 2,710 Repayments of long-term debt(1,151)(601)(417)Proceeds from issuance of common stock270 322 366 Dividends paid(1,092)(1,012)(935)Other, net(12)(15)(10)Net cash provided by financing activities617 666 2,135 Net change in cash and cash equivalents18 (55)37 Cash, cash equivalents and restricted cash at beginning of period111 166 129 Cash, cash equivalents and restricted cash at end of period$129 $111 $166 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(945)$(887)$(788)Cash received (paid) for income taxes, net92 (15)(4)Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$553 $626 $501 Inventory transfers to property, plant and equipment197 78 87 Operating lease right-of-use assets238 141 8 Allowance for equity funds used during construction91 75 73 Issuance of common stock for reinvested dividends and/or equity awards64 57 60 See Notes to Consolidated Financial Statements 49 49 49 Table of Contents Table of Contents" **Prior (2023):** (amounts in millions) Year Ended Dec. 31 202220212020Operating activities Net income$1,736 $1,597 $1,473 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,436 2,143 1,959 Nuclear fuel amortization118 114 123 Deferred income taxes(140)(79)(8)Allowance for equity funds used during construction(75)(73)(115)Earnings from equity method investments(36)(62)(40)Dividends from equity method investments37 42 42 Provision for bad debts73 60 60 Share-based compensation expense20 31 73 Changes in operating assets and liabilities:Accounts receivable(429)(164)(154)Accrued unbilled revenues(243)(149)(3)Inventories(203)(126)(80)Other current assets(58)(34)(45)Accounts payable195 138 (33)Net regulatory assets and liabilities570 (973)(144)Other current liabilities102 (1)29 Pension and other employee benefit obligations(49)(135)(125)Other, net(122)(140)(164)Net cash provided by operating activities3,932 2,189 2,848 Investing activitiesCapital/construction expenditures(4,638)(4,244)(5,369)Sale of MEC - - 684 Purchase of investment securities(1,332)(757)(1,398)Proceeds from the sale of investment securities1,297 743 1,378 Other, net20 (29)(35)Net cash used in investing activities(4,653)(4,287)(4,740)Financing activities(Repayments of) proceeds from short-term borrowings, net(192)421 (11)Proceeds from issuances of long-term debt2,164 2,710 2,940 Repayments of long-term debt(601)(417)(1,001)Proceeds from issuance of common stock322 366 727 Dividends paid(1,012)(935)(856)Other, net(15)(10)(26)Net cash provided by financing activities666 2,135 1,773 Net change in cash and cash equivalents(55)37 (119)Cash, cash equivalents and restricted cash at beginning of period166 129 248 Cash, cash equivalents and restricted cash at end of period$111 $166 $129 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(887)$(788)$(758)Cash (paid) received for income taxes, net(15)(4)12 Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$626 $501 $400 Inventory transfers to property, plant and equipment78 87 275 Operating lease right-of-use assets141 8 369 Allowance for equity funds used during construction75 73 115 Issuance of common stock for reinvested dividends and/or equity awards57 60 67 See Notes to Consolidated Financial Statements 50 50 50 Table of Contents Table of Contents **Current (2024):** (amounts in millions) Year Ended Dec. 31 202320222021Operating activities Net income$1,771 $1,736 $1,597 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,471 2,436 2,143 Nuclear fuel amortization96 118 114 Deferred income taxes(59)(140)(79)Allowance for equity funds used during construction(91)(75)(73)Earnings from equity method investments(35)(36)(62)Dividends from equity method investments35 37 42 Provision for bad debts79 73 60 Share-based compensation expense25 20 31 Changes in operating assets and liabilities:Accounts receivable(27)(429)(164)Accrued unbilled revenues252 (243)(149)Inventories(98)(203)(126)Other current assets86 (58)(34)Accounts payable(149)195 138 Net regulatory assets and liabilities911 570 (973)Other current liabilities200 102 (1)Pension and other employee benefit obligations17 (49)(135)Other, net(157)(122)(140)Net cash provided by operating activities5,327 3,932 2,189 Investing activitiesCapital/construction expenditures(5,854)(4,638)(4,244)Purchase of investment securities(994)(1,332)(757)Proceeds from the sale of investment securities959 1,297 743 Other, net(37)20 (29)Net cash used in investing activities(5,926)(4,653)(4,287)Financing activities(Repayments of) proceeds from short-term borrowings, net(28)(192)421 Proceeds from issuances of long-term debt2,630 2,164 2,710 Repayments of long-term debt(1,151)(601)(417)Proceeds from issuance of common stock270 322 366 Dividends paid(1,092)(1,012)(935)Other, net(12)(15)(10)Net cash provided by financing activities617 666 2,135 Net change in cash and cash equivalents18 (55)37 Cash, cash equivalents and restricted cash at beginning of period111 166 129 Cash, cash equivalents and restricted cash at end of period$129 $111 $166 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(945)$(887)$(788)Cash received (paid) for income taxes, net92 (15)(4)Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$553 $626 $501 Inventory transfers to property, plant and equipment197 78 87 Operating lease right-of-use assets238 141 8 Allowance for equity funds used during construction91 75 73 Issuance of common stock for reinvested dividends and/or equity awards64 57 60 See Notes to Consolidated Financial Statements 49 49 49 Table of Contents Table of Contents --- ## Modified: Results of Operations **Key changes:** - Reworded sentence: "31: 20232022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSGAAP Diluted EPSNSP-Minnesota$1.28 $1.23 PSCo1.26 1.33 SPS0.70 0.64 NSP-Wisconsin0.25 0.23 Earnings from equity method investments - WYCO0.04 0.04 Regulated utility (a)3.52 3.47 Xcel Energy Inc." **Prior (2023):** Diluted EPS for Xcel Energy at Dec. 31: 20222021Diluted Earnings (Loss) Per ShareGAAP and Ongoing Diluted EPSGAAP and Ongoing Diluted EPSPSCo$1.33 $1.22 NSP-Minnesota1.23 1.12 SPS0.64 0.59 NSP-Wisconsin0.23 0.20 Earnings from equity method investments - WYCO0.04 0.05 Regulated utility (a)3.47 3.18 Xcel Energy Inc. and Other(0.29)(0.22)Total (a)$3.17 $2.96 Regulated utility (a) Total (a) (a) Amounts may not add due to rounding. Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors. **Current (2024):** Diluted EPS for Xcel Energy at Dec. 31: 20232022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSGAAP Diluted EPSNSP-Minnesota$1.28 $1.23 PSCo1.26 1.33 SPS0.70 0.64 NSP-Wisconsin0.25 0.23 Earnings from equity method investments - WYCO0.04 0.04 Regulated utility (a)3.52 3.47 Xcel Energy Inc. and Other(0.31)(0.29)GAAP Diluted EPS (a)3.21 3.17 Loss on Comanche Unit 3 litigation0.05 - Workforce reduction expenses0.09 - Ongoing Diluted EPS (a)$3.35 $3.17 Regulated utility (a) GAAP Diluted EPS (a) Ongoing Diluted EPS (a) (a)Amounts may not add due to rounding. Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors. --- ## Modified: Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation. **Key changes:** - Reworded sentence: "All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training." - Added sentence: "Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, PI and Monticello." - Added sentence: "Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S." - Added sentence: "reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved." - Added sentence: "NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses." **Prior (2023):** We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to comply with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to comply with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows. **Current (2024):** We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows. Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota's nuclear operations. Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. --- ## Modified: Change in Electric Margin **Key changes:** - Reworded sentence: "(Millions of Dollars)2023 vs." **Prior (2023):** (Millions of Dollars)2022 vs. 2021Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin)$506 Revenue recognition for the Texas rate case surcharge (a)85 Sales and demand (b)80 Non-fuel riders64 Wholesale transmission (net)50 Estimated impact of weather (net of decoupling/sales true-up)33 PTCs flowed back to customers (offset by lower ETR)(150)Other (net)(22)Total increase$646 Revenue recognition for the Texas rate case surcharge (a) Sales and demand (b) (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. **Current (2024):** (Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI)$100 Non-fuel riders89 Sales and demand (a)57 Wholesale transmission (net)28 Revenue recognition of the Texas rate case surcharge (b)(85)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)Other (net)(17)Total increase$50 Sales and demand (a) Revenue recognition of the Texas rate case surcharge (b) (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. --- ## Modified: 4. Regulatory Assets and Liabilities **Key changes:** - Reworded sentence: "31, 2022 (a)Regulatory AssetsCurrentNoncurrentCurrentNoncurrentPension and retiree medical obligations11Various$27 $1,106 $22 $1,069 Recoverable deferred taxes on AFUDCPlant lives - 332 - 292 Net AROs (b) 1, 12Various - 316 - 339 Excess deferred taxes - TCJA 7Various10 198 13 205 Depreciation differencesOne to 12 years17 189 17 193 Environmental remediation costs1, 12Various15 94 20 92 Deferred natural gas, electric, steam energy/fuel costsOne to three years239 80 581 299 Conservation programs (c)1One to two years19 54 16 36 Purchased power contract costsTerm of related contract4 40 10 36 PI extended power uprate11 years4 38 4 42 Benson biomass PPA termination and asset purchaseFive years10 36 10 45 Sales true-up and revenue decouplingOne to two years7 33 54 - State commission adjustments Plant lives1 32 1 33 Losses on reacquired debtTerm of related debt2 30 3 32 MISO capacity revenue trackerOne to two years36 26 - - Gas pipeline inspection and remediation costsOne to two years40 25 42 13 Contract valuation adjustments (d) 1, 10Term of related contract18 22 28 28 Nuclear refueling outage costs1One to two years43 19 30 12 Grid modernization costsOne to two years16 17 14 24 Renewable resources and environmental initiativesOne to two years38 5 50 6 OtherVarious65 106 144 75 Total regulatory assets$611 $2,798 $1,059 $2,871" **Prior (2023):** Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2022Dec. 31, 2021 (a)Regulatory AssetsCurrentNoncurrentCurrentNoncurrentPension and retiree medical obligations11Various$22 $1,069 $77 $944 Net AROs (b) 1, 12Various - 339 - (112)Deferred natural gas, electric, steam energy/fuel costsOne to five years581 299 504 543 Recoverable deferred taxes on AFUDCPlant lives - 292 - 289 Excess deferred taxes - TCJA 7Various13 205 14 219 Depreciation differencesOne to 12 years17 193 16 173 Environmental remediation costs1, 12Various20 92 14 92 Benson biomass PPA termination and asset purchaseSix years10 45 10 55 PI extended power uprate12 years4 42 4 46 Conservation programs (c)1One to two years16 36 21 35 Purchased power contract costsTerm of related contract10 36 9 45 State commission adjustments Plant lives1 33 1 32 Losses on reacquired debtTerm of related debt3 32 3 35 Contract valuation adjustments (d) 1, 10Term of related contract28 28 22 34 Grid modernization costsVarious14 24 - 36 Gas pipeline inspection and remediation costsOne to two years42 13 33 12 Nuclear refueling outage costs1One to two years30 12 37 16 Renewable resources and environmental initiativesOne to two years50 6 170 48 Texas revenue surchargesLess than one year69 - 20 64 Sales true-up and revenue decouplingOne to two years54 - 33 56 OtherVarious75 75 118 76 Total regulatory assets$1,059 $2,871 $1,106 $2,738 **Current (2024):** Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2023Dec. 31, 2022 (a)Regulatory AssetsCurrentNoncurrentCurrentNoncurrentPension and retiree medical obligations11Various$27 $1,106 $22 $1,069 Recoverable deferred taxes on AFUDCPlant lives - 332 - 292 Net AROs (b) 1, 12Various - 316 - 339 Excess deferred taxes - TCJA 7Various10 198 13 205 Depreciation differencesOne to 12 years17 189 17 193 Environmental remediation costs1, 12Various15 94 20 92 Deferred natural gas, electric, steam energy/fuel costsOne to three years239 80 581 299 Conservation programs (c)1One to two years19 54 16 36 Purchased power contract costsTerm of related contract4 40 10 36 PI extended power uprate11 years4 38 4 42 Benson biomass PPA termination and asset purchaseFive years10 36 10 45 Sales true-up and revenue decouplingOne to two years7 33 54 - State commission adjustments Plant lives1 32 1 33 Losses on reacquired debtTerm of related debt2 30 3 32 MISO capacity revenue trackerOne to two years36 26 - - Gas pipeline inspection and remediation costsOne to two years40 25 42 13 Contract valuation adjustments (d) 1, 10Term of related contract18 22 28 28 Nuclear refueling outage costs1One to two years43 19 30 12 Grid modernization costsOne to two years16 17 14 24 Renewable resources and environmental initiativesOne to two years38 5 50 6 OtherVarious65 106 144 75 Total regulatory assets$611 $2,798 $1,059 $2,871 --- ## Modified: Capital Requirements **Key changes:** - Reworded sentence: "Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation." **Prior (2023):** Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy's financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, 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. 41 41 41 Table of Contents Table of Contents **Current (2024):** Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy's financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation. --- ## Modified: Dec. 31, 2022 (a) **Key changes:** - Reworded sentence: "Net AROs (b) Excess deferred taxes - TCJA One to 12 years One One to three years One three Conservation programs (c) One to two years One two 11 years Five years Five One to two years One two One to two years One two One to two years One two Contract valuation adjustments (d) One to two years One two One to two years One two One to two years One two (a)Prior period amounts have been reclassified to conform with current year presentation." - Added sentence: "Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion." - Reworded sentence: "Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions." - Reworded sentence: "31, 2023Year Ended Dec." - Reworded sentence: "31, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations." **Prior (2023):** Net AROs (b) One to five years One five Excess deferred taxes - TCJA One to 12 years One Six years Six 12 years Conservation programs (c) One to two years One two Contract valuation adjustments (d) One to two years One two One to two years One two One to two years One two Less than one year one One to two years One two (a)Prior period amounts have been restated to conform with current year presentation. (b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (c)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. 57 57 57 Table of Contents Table of Contents Components of regulatory liabilities: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2022Dec. 31, 2021 (a)Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentDeferred income tax adjustments and TCJA refunds (b)7Various$9 $3,110 $26 $3,230 Plant removal costs1, 12Various - 1,819 - 1,655 Effects of regulation on employee benefit costs (c)Various - 247 - 235 Renewable resources and environmental initiativesVarious6 173 1 101 Revenue decouplingOne to two years - 77 9 41 ITC deferrals1Various1 61 - 53 Formula ratesOne to two years32 17 19 11 Contract valuation adjustments (d)1, 10One to two years175 1 56 1 Deferred natural gas, electric, steam energy/fuel costsLess than one year39 - 50 - Conservation programs (e)1Less than one year72 - 42 - DOE settlementVarious12 3 14 14 OtherVarious72 61 54 64 Total regulatory liabilities (f)$418 $5,569 $271 $5,405 **Current (2024):** Net AROs (b) Excess deferred taxes - TCJA One to 12 years One One to three years One three Conservation programs (c) One to two years One two 11 years Five years Five One to two years One two One to two years One two One to two years One two Contract valuation adjustments (d) One to two years One two One to two years One two One to two years One two (a)Prior period amounts have been reclassified to conform with current year presentation. Prior period amounts have been reclassified to conform with current year presentation. (b)The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments. In 2023, the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability. The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments. In 2023, the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability. (c)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. 57 57 57 Table of Contents Table of Contents Components of regulatory liabilities: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2023Dec. 31, 2022Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentDeferred income tax adjustments and TCJA refunds (a)7Various$7 $3,015 $9 $3,110 Plant removal costs1, 12Various - 1,984 - 1,819 Effects of regulation on employee benefit costs (b)Various - 253 - 247 Renewable resources and environmental initiativesVarious9 188 6 173 Net AROs (c)Various - 90 - - Sales true-up and revenue decouplingTwo years18 76 - 77 ITC deferrals1Various1 60 1 61 LP&L departure paymentUp to 10 years33 33 - - Formula ratesOne to two years29 18 32 17 DOE settlementOne to two years18 6 12 3 Deferred natural gas, electric, steam energy/fuel costsLess than one year220 - 39 - Contract valuation adjustments (d)1, 10Less than one year56 - 175 1 Conservation programs (e)1Less than one year47 - 72 - OtherVarious90 104 72 61 Total regulatory liabilities (f)$528 $5,827 $418 $5,569 Deferred income tax adjustments and TCJA refunds (a) Effects of regulation on employee benefit costs (b) Net AROs (c) Two years Two ITC deferrals Up to 10 years One to two years One two One to two years One two Less than one year one Contract valuation adjustments (d) Less than one year one Conservation programs (e) Less than one year one Total regulatory liabilities (f) (a)Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA. Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA. (b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. (c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (e)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (f)Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities. Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities. Xcel Energy's regulatory assets not earning a return include past expenditures of $1,085 million and $1,020 million at Dec. 31, 2023 and 2022 respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return. 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2023Year Ended Dec. 31202320222021Borrowing limit$3,550 $3,550 $3,550 $3,100 Amount outstanding at period end785 785 813 1,005 Average amount outstanding339 491 552 1,399 Maximum amount outstanding785 1,241 1,357 2,054 Weighted average interest rate, computed on a daily basis5.51 %5.12 %1.47 %0.57 %Weighted average interest rate at period end5.52 5.52 4.66 0.31 Bilateral Credit Agreement - In April 2023, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2023 and 2022, there were $44 million and $43 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Terms of Credit Agreements - In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2023Year Ended Dec. 31202320222021Borrowing limit$3,550 $3,550 $3,550 $3,100 Amount outstanding at period end785 785 813 1,005 Average amount outstanding339 491 552 1,399 Maximum amount outstanding785 1,241 1,357 2,054 Weighted average interest rate, computed on a daily basis5.51 %5.12 %1.47 %0.57 %Weighted average interest rate at period end5.52 5.52 4.66 0.31 --- ## Modified: Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS) **Key changes:** - Added sentence: "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." - Reworded sentence: "These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP." - Reworded sentence: "31:20232022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSGAAP Diluted EPSNSP-Minnesota$1.28 $1.23 PSCo1.26 1.33 SPS0.70 0.64 NSP-Wisconsin0.25 0.23 Earnings from equity method investments - WYCO0.04 0.04 Regulated utility (a)3.52 3.47 Xcel Energy Inc." **Prior (2023):** GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.'s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy's core earnings and underlying performance. 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. Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:20222021Diluted Earnings (Loss) Per ShareGAAP and Ongoing Diluted EPSGAAP and Ongoing Diluted EPSPSCo$1.33 $1.22 NSP-Minnesota1.23 1.12 SPS0.64 0.59 NSP-Wisconsin0.23 0.20 Earnings from equity method investments - WYCO0.04 0.05 Regulated utility (a)3.47 3.18 Xcel Energy Inc. and Other(0.29)(0.22)Total (a)$3.17 $2.96 (a) Amounts may not add due to rounding.Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2022 Comparison with 2021Xcel 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 Inc. and Other - Earnings decreased $0.07 per share year-to-date due to higher interest charges and decreased earnings from EIP investments. **Current (2024):** GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.'s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy's core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted 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. 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)20232022GAAP net income$1,771 $1,736 Loss on Comanche Unit 3 litigation35 - Workforce reduction expenses72 - Less: tax effect of adjustments(27) - Ongoing earnings$1,851 $1,736 Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 - 0.25 Earnings from equity method investments - WYCO0.04 - 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31) - (0.31)Total (a)$3.21 0.14 $3.35 Twelve Months Ended Dec. 31, 2022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.23 $ - $1.23 PSCo1.33 - 1.33 SPS0.64 - 0.64 NSP-Wisconsin0.23 - 0.23 Earnings from equity method investments - WYCO0.04 - 0.04 Regulated utility (a)3.47 - 3.47 Xcel Energy Inc. and Other(0.29) - (0.29)Total (a)$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. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings: (Millions of Dollars)20232022GAAP net income$1,771 $1,736 Loss on Comanche Unit 3 litigation35 - Workforce reduction expenses72 - Less: tax effect of adjustments(27) - Ongoing earnings$1,851 $1,736 Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 - 0.25 Earnings from equity method investments - WYCO0.04 - 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31) - (0.31)Total (a)$3.21 0.14 $3.35 PSCo (a) Regulated utility (a) Total (a) Twelve Months Ended Dec. 31, 2022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.23 $ - $1.23 PSCo1.33 - 1.33 SPS0.64 - 0.64 NSP-Wisconsin0.23 - 0.23 Earnings from equity method investments - WYCO0.04 - 0.04 Regulated utility (a)3.47 - 3.47 Xcel Energy Inc. and Other(0.29) - (0.29)Total (a)$3.17 - $3.17 Regulated utility (a) Total (a) (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. 26 26 26 Table of Contents Table of Contents Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:20232022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSGAAP Diluted EPSNSP-Minnesota$1.28 $1.23 PSCo1.26 1.33 SPS0.70 0.64 NSP-Wisconsin0.25 0.23 Earnings from equity method investments - WYCO0.04 0.04 Regulated utility (a)3.52 3.47 Xcel Energy Inc. and Other(0.31)(0.29)GAAP Diluted EPS (a)3.21 3.17 Loss on Comanche Unit 3 litigation0.05 - Workforce reduction expenses0.09 - Ongoing Diluted EPS (a)$3.35 $3.17 (a)Amounts may not add due to rounding.Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2023 Comparison with 2022Xcel 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 - 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 EPSComponents significantly contributing to changes in EPS:2023 vs. 2022Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS - 2022$3.17 Components of change - 2023 vs. 2022Higher electric revenues, net of electric fuel and purchased power0.07 Lower O&M expenses0.06 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 transported0.03 Higher interest expense(0.14)Higher depreciation and amortization(0.05)Workforce reduction expenses(0.09)Loss on Comanche Unit 3 litigation(0.05)Other (net)0.06 GAAP diluted EPS - 2023$3.21 Workforce reduction expenses0.09 Loss on Comanche Unit 3 litigation0.05 Ongoing diluted EPS - 2023$3.35 ROE for Xcel Energy and its utility subsidiaries:20232022ROEGAAP ROEOngoing ROEGAAP and Ongoing ROENSP-Minnesota8.82 %9.11 %8.76 %PSCo7.32 7.77 8.23 SPS9.80 9.98 9.36 NSP-Wisconsin10.38 10.67 10.57 Operating Companies8.45 8.79 8.74 Xcel Energy10.33 10.79 10.76 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy's financial performance. However, electric decoupling mechanisms in Colorado (mechanism expired in September 2023) and electric sales true-up mechanisms in Minnesota and gas decoupling mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in those jurisdictions. Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:20232022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSGAAP Diluted EPSNSP-Minnesota$1.28 $1.23 PSCo1.26 1.33 SPS0.70 0.64 NSP-Wisconsin0.25 0.23 Earnings from equity method investments - WYCO0.04 0.04 Regulated utility (a)3.52 3.47 Xcel Energy Inc. and Other(0.31)(0.29)GAAP Diluted EPS (a)3.21 3.17 Loss on Comanche Unit 3 litigation0.05 - Workforce reduction expenses0.09 - Ongoing Diluted EPS (a)$3.35 $3.17 (a)Amounts may not add due to rounding.Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2023 Comparison with 2022Xcel 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. --- ## Modified: CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME **Key changes:** - Reworded sentence: "31202320222021Net income$1,771 $1,736 $1,597 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical (losses) gains arising during the period, net of tax (4)5 - Reclassification of losses to net income, net of tax 2 4 8 Derivative instruments:Net fair value (decrease) increase, net of tax(2)16 4 Reclassification of losses to net income, net of tax 3 5 6 Total other comprehensive (loss) income(1)30 18 Total comprehensive income$1,770 $1,766 $1,615 See Notes to Consolidated Financial Statements 48 48 48 Table of Contents Table of Contents" **Prior (2023):** (amounts in millions) Year Ended Dec. 31202220212020Net income$1,736 $1,597 $1,473 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical gains (losses) arising during the period, net of tax of $1, $ - and $(2), respectively5 - (5)Reclassification of losses to net income, net of tax of $1, $3 and $3, respectively4 8 10 Derivative instruments:Net fair value increase (decrease), net of tax of $6, $1 and $(3), respectively16 4 (10)Reclassification of losses to net income, net of tax of $2, $2 and $2, respectively5 6 5 Total other comprehensive income30 18 - Total comprehensive income$1,766 $1,615 $1,473 See Notes to Consolidated Financial Statements Net pension and retiree medical gains (losses) arising during the period, net of tax of $1, $ - and $(2), respectively Reclassification of losses to net income, net of tax of $1, $3 and $3, respectively Net fair value increase (decrease), net of tax of $6, $1 and $(3), respectively Reclassification of losses to net income, net of tax of $2, $2 and $2, respectively 49 49 49 Table of Contents Table of Contents **Current (2024):** (amounts in millions) Year Ended Dec. 31202320222021Net income$1,771 $1,736 $1,597 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical (losses) gains arising during the period, net of tax (4)5 - Reclassification of losses to net income, net of tax 2 4 8 Derivative instruments:Net fair value (decrease) increase, net of tax(2)16 4 Reclassification of losses to net income, net of tax 3 5 6 Total other comprehensive (loss) income(1)30 18 Total comprehensive income$1,770 $1,766 $1,615 See Notes to Consolidated Financial Statements 48 48 48 Table of Contents Table of Contents --- ## Modified: Pending and Recently Concluded Regulatory Proceedings **Key changes:** - Reworded sentence: "The rate request was based on a ROE of 10.2%, a 52.5% equity ratio and forward test years." - Reworded sentence: "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%." - Reworded sentence: "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." - Reworded sentence: "NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause." - Reworded sentence: "This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility." **Prior (2023):** 2022 Minnesota Electric Rate Case - In 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. In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/A In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows:•ALJ Report: March 31, 2023.•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. 1, 2022.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. 1, 2021. 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. 1, 2022.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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows: •ALJ Report: March 31, 2023. •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. 1, 2022. 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. 1, 2021. 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. 1, 2022. 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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. 30 30 30 Table of Contents Table of Contents 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.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and 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. 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 OperationsNSP-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 Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 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.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 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. **Current (2024):** 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. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In October 2023, the MPUC denied NSP-Minnesota's request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023. 2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota's request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024). Next steps in the procedural schedule are expected to be as follows: •Intervenor direct testimony: April 19, 2024 •Rebuttal testimony: May 24, 2024 •Evidentiary hearings: July 10-12, 2024 •ALJ Report: October 28, 2024 •MPUC Order Due: March 14, 2025 30 30 30 Table of Contents Table of Contents 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin's natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-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 AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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.Recently Concluded Regulatory ProceedingsWisconsin 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. 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.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. 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. --- ## Modified: Electric Revenues, Fuel and Purchased Power and Electric Margin **Key changes:** - Reworded sentence: "(Millions of Dollars)20232022Electric revenues$11,446 $12,123 Electric fuel and purchased power(4,278)(5,005)Electric margin$7,168 $7,118 28 28 28 Table of Contents Table of Contents Change in Electric Margin(Millions of Dollars)2023 vs." - Reworded sentence: "Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin(Millions of Dollars)20232022Natural gas revenues$2,645 $3,080 Cost of natural gas sold and transported(1,456)(1,910)Natural gas margin$1,189 $1,170 Change in Natural Gas Margin(Millions of Dollars)2023 vs." **Prior (2023):** (Millions of Dollars)20222021Electric revenues$12,123 $11,205 Electric fuel and purchased power(5,005)(4,733)Electric margin$7,118 $6,472 Change in Electric Margin(Millions of Dollars)2022 vs. 2021Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin)$506 Revenue recognition for the Texas rate case surcharge (a)85 Sales and demand (b)80 Non-fuel riders64 Wholesale transmission (net)50 Estimated impact of weather (net of decoupling/sales true-up)33 PTCs flowed back to customers (offset by lower ETR)(150)Other (net)(22)Total increase$646 (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.Natural Gas MarginNatural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms. Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin(Millions of Dollars)20222021Natural gas revenues$3,080 $2,132 Cost of natural gas sold and transported(1,910)(1,081)Natural gas margin$1,170 $1,051 Change in Natural Gas Margin(Millions of Dollars)2022 vs. 2021Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, North Dakota)$61 Estimated impact of weather46 Conservation revenue (offset in expenses)13 Infrastructure and integrity riders9 Winter Storm Uri disallowances(20)Other (net)10 Total increase$119 Non-Fuel Operating Expenses and Other ItemsO&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; and other. **Current (2024):** (Millions of Dollars)20232022Electric revenues$11,446 $12,123 Electric fuel and purchased power(4,278)(5,005)Electric margin$7,168 $7,118 28 28 28 Table of Contents Table of Contents Change in Electric Margin(Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI)$100 Non-fuel riders89 Sales and demand (a)57 Wholesale transmission (net)28 Revenue recognition of the Texas rate case surcharge (b)(85)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)Other (net)(17)Total increase$50 (a)Sales excludes weather impact, net of partial decoupling in Colorado (mechanism expired in September 2023) and sales true-up mechanism in Minnesota.(b)The decline in electric margin is due to the recognition of the Texas rate case outcome in the second quarter of 2022, which was largely offset by recognition of previously deferred costs. Natural Gas MarginNatural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms. Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin(Millions of Dollars)20232022Natural gas revenues$2,645 $3,080 Cost of natural gas sold and transported(1,456)(1,910)Natural gas margin$1,189 $1,170 Change in Natural Gas Margin(Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (CO, WI, MI)$50 Estimated impact of weather (net of decoupling)(25)Other (net)(6)Total increase$19 Non-Fuel Operating Expenses and Other ItemsO&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 $102 million in 2023. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20232022Xcel Energy Inc. financing costs$(174)$(153)Venture Holdings (a)3 5 Xcel Energy Inc. taxes and other results(2)(12)Total Xcel Energy Inc. and other costs$(173)$(160)(Diluted Earnings (Loss) Per Share)20232022Xcel Energy Inc. financing costs$(0.32)$(0.28)Venture Holdings (a)0.01 0.01 Xcel Energy Inc. taxes and other results - (0.02)Total Xcel Energy Inc. and other costs$(0.31)$(0.29)(a)Amounts include gains or losses associated with EIP investments.Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2022 Comparison with 2021 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2021 to Dec. 31, 2022 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2022, which was filed with the SEC on Feb. 23, 2023. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas. Change in Electric Margin(Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI)$100 Non-fuel riders89 Sales and demand (a)57 Wholesale transmission (net)28 Revenue recognition of the Texas rate case surcharge (b)(85)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)Other (net)(17)Total increase$50 (a)Sales excludes weather impact, net of partial decoupling in Colorado (mechanism expired in September 2023) and sales true-up mechanism in Minnesota.(b)The decline in electric margin is due to the recognition of the Texas rate case outcome in the second quarter of 2022, which was largely offset by recognition of previously deferred costs. Natural Gas MarginNatural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms. Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin(Millions of Dollars)20232022Natural gas revenues$2,645 $3,080 Cost of natural gas sold and transported(1,456)(1,910)Natural gas margin$1,189 $1,170 Change in Natural Gas Margin(Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (CO, WI, MI)$50 Estimated impact of weather (net of decoupling)(25)Other (net)(6)Total increase$19 Non-Fuel Operating Expenses and Other ItemsO&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. --- ## Modified: We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows. **Key changes:** - Reworded sentence: "Health epidemics impact countries, communities, supply chains and markets." - Added sentence: "Operations could be impacted by war, terrorism or other events." - Added sentence: "Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities." - Added sentence: "Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets." - Added sentence: "These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business." **Prior (2023):** Health epidemics continue to impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy. We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. **Current (2024):** Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy. We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. Operations could be impacted by war, terrorism or other events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cybersecurity incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. --- ## Modified: We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts. **Key changes:** - Added sentence: "Climate change may impact the economy, which could impact our sales and revenues." - Added sentence: "The price of energy has an impact on the economic health of our communities." - Added sentence: "The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods." - Added sentence: "To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.We establish strategies and expectations related to climate change and other environmental matters." - Added sentence: "Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control." **Prior (2023):** Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions. We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B - UNRESOLVED STAFF COMMENTSNone. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B - UNRESOLVED STAFF COMMENTS ITEM 1B - UNRESOLVED STAFF COMMENTS None. 23 23 23 Table of Contents Table of Contents ITEM 2 - PROPERTIESVirtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.NSP-MinnesotaStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 Unit 3Coal1987517 (b)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RefuseVarious36 (c)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005327 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018494 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas1974 - 2005447 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 6 UnitsNatural Gas1972252 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Various locations, 7 UnitsNatural GasVarious10 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)Border-Rolette County, ND, 75 UnitsWind2015148 (d)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)Dakota Range, SD, 72 UnitsWind2022298 (d)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)Grand Meadow-Mower County, MN, 67 UnitsWind200899 (d)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)Mower-Mower County, MN, 43 UnitsWind202191 (d)Nobles-Nobles County, MN, 133 Units (e)Wind2010200 (d)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (d)Total8,949 (a)Summer 2022 net dependable capacity.(b)Based on NSP-Minnesota's ownership of 59%.(c)Refuse-derived fuel is made from municipal solid waste.(d)Capacity is attainable only when wind conditions are sufficiently available.(e)Repowered in 2022.NSP-WisconsinStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974122 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Hydro:Various locations, 62 UnitsHydroVarious135 Total548 (a)Summer 2022 net dependable capacity.(b)Refuse-derived fuel is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975335 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 Manchief, CO, 2 Units (e)Natural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 Various locations, 8 UnitsNatural GasVarious251 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Total6,151 (a)Summer 2022 net dependable capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Purchased in 2022. (f)Capacity is attainable only when wind conditions are sufficiently available. ITEM 2 - PROPERTIESVirtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.NSP-MinnesotaStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 Unit 3Coal1987517 (b)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RefuseVarious36 (c)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005327 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018494 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas1974 - 2005447 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 6 UnitsNatural Gas1972252 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Various locations, 7 UnitsNatural GasVarious10 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)Border-Rolette County, ND, 75 UnitsWind2015148 (d)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)Dakota Range, SD, 72 UnitsWind2022298 (d)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)Grand Meadow-Mower County, MN, 67 UnitsWind200899 (d)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)Mower-Mower County, MN, 43 UnitsWind202191 (d)Nobles-Nobles County, MN, 133 Units (e)Wind2010200 (d)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (d)Total8,949 (a)Summer 2022 net dependable capacity.(b)Based on NSP-Minnesota's ownership of 59%.(c)Refuse-derived fuel is made from municipal solid waste.(d)Capacity is attainable only when wind conditions are sufficiently available.(e)Repowered in 2022. ITEM 2 - PROPERTIES ITEM 2 - PROPERTIES Virtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures. NSP-MinnesotaStation, Location and Unit at Dec. 31, 2022FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 Unit 3Coal1987517 (b)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RefuseVarious36 (c)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005327 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018494 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas1974 - 2005447 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 6 UnitsNatural Gas1972252 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Various locations, 7 UnitsNatural GasVarious10 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)Border-Rolette County, ND, 75 UnitsWind2015148 (d)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)Dakota Range, SD, 72 UnitsWind2022298 (d)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)Grand Meadow-Mower County, MN, 67 UnitsWind200899 (d)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)Mower-Mower County, MN, 43 UnitsWind202191 (d)Nobles-Nobles County, MN, 133 Units (e)Wind2010200 (d)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (d)Total8,949 **Current (2024):** Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B - UNRESOLVED STAFF COMMENTSNone. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions. We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B - UNRESOLVED STAFF COMMENTS ITEM 1B - UNRESOLVED STAFF COMMENTS None. 22 22 22 Table of Contents Table of Contents ITEM 1C - CYBERSECURITYAs described in Item 1A - Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.Annually, as part of Xcel Energy's enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy's business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy's cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor's risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats.The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy's incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board of Directors conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis.Cybersecurity risks are a part of Xcel Energy's normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report. ITEM 1C - CYBERSECURITYAs described in Item 1A - Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.Annually, as part of Xcel Energy's enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy's business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy's cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor's risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate. ITEM 1C - CYBERSECURITY As described in Item 1A - Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program. Annually, as part of Xcel Energy's enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy's business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy's cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer. Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor's risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate. Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats.The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy's incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board of Directors conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis.Cybersecurity risks are a part of Xcel Energy's normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report. Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats. The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy's incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees. The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board of Directors conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis. Cybersecurity risks are a part of Xcel Energy's normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report. 23 23 23 Table of Contents Table of Contents ITEM 2 - PROPERTIESVirtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.NSP-MinnesotaStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 (b)Unit 3Coal1987517 (c)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (d)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (e)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (e)Border-Rolette County, ND, 75 UnitsWind2015148 (e)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (e)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (e)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (e)Dakota Range, SD, 72 UnitsWind2022298 (e)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (e)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (e)Grand Meadow-Mower County, MN, 67 Units (f)Wind200899 (e)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (e)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (e)Mower-Mower County, MN, 43 UnitsWind202191 (e)Nobles-Nobles County, MN, 133 UnitsWind2010200 (e)Northern Wind-Murray County, MN, 37 Units (g)Wind202392 (e)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (e)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (e)Total9,081 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023.(c)Based on NSP-Minnesota's ownership of 59%.(d)RDF is made from municipal solid waste.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota's wind facilities had a weighted-average capacity factors of 43%.(f)Repowered in 2023.(g)Purchased in 2023.NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo's wind facilities had a weighted-average capacity factors of 43%. ITEM 2 - PROPERTIESVirtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.NSP-MinnesotaStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 (b)Unit 3Coal1987517 (c)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (d)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (e)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (e)Border-Rolette County, ND, 75 UnitsWind2015148 (e)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (e)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (e)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (e)Dakota Range, SD, 72 UnitsWind2022298 (e)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (e)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (e)Grand Meadow-Mower County, MN, 67 Units (f)Wind200899 (e)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (e)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (e)Mower-Mower County, MN, 43 UnitsWind202191 (e)Nobles-Nobles County, MN, 133 UnitsWind2010200 (e)Northern Wind-Murray County, MN, 37 Units (g)Wind202392 (e)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (e)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (e)Total9,081 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023.(c)Based on NSP-Minnesota's ownership of 59%.(d)RDF is made from municipal solid waste.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota's wind facilities had a weighted-average capacity factors of 43%.(f)Repowered in 2023.(g)Purchased in 2023. ITEM 2 - PROPERTIES ITEM 2 - PROPERTIES Virtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures. NSP-MinnesotaStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 (b)Unit 3Coal1987517 (c)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (d)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (e)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (e)Border-Rolette County, ND, 75 UnitsWind2015148 (e)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (e)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (e)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (e)Dakota Range, SD, 72 UnitsWind2022298 (e)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (e)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (e)Grand Meadow-Mower County, MN, 67 Units (f)Wind200899 (e)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (e)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (e)Mower-Mower County, MN, 43 UnitsWind202191 (e)Nobles-Nobles County, MN, 133 UnitsWind2010200 (e)Northern Wind-Murray County, MN, 37 Units (g)Wind202392 (e)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (e)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (e)Total9,081 --- ## Modified: Pending and Recently Concluded Regulatory Proceedings **Key changes:** - Reworded sentence: "Colorado Electric Rate Case - In 2022, PSCo filed a Colorado electric rate case seeking a revised net increase of $253 million." - Reworded sentence: "Much of PSCo's long-term purchased power is for wind, solar and storage resources." - Reworded sentence: "NMPRCRetail electric operations, retail rates and services and the construction of transmission or generation.Reviews Integrated Resource Plans for meeting future energy needs.FERCWholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.SPP RTO and SPP Integrated and Wholesale MarketsSPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets." - Reworded sentence: "DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAdvanced Metering System SurchargeRecovers costs incurred in deployment of the Advanced Metering System in Texas.Consulting Fee RiderRecovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT.Distribution Cost Recovery FactorRecovers distribution costs not included in rates in Texas.Electric Vehicle RiderRecovers costs of the Transportation Electrification Plan in New Mexico.Energy Efficiency Cost Recovery FactorRecovers costs for energy efficiency programs in Texas.Energy Efficiency RiderRecovers costs for energy efficiency programs in New Mexico.Fixed Fuel and Purchased Recovery FactorProvides for the over- or under-recovery of energy expenses in Texas." - Reworded sentence: "Much of PSCo's long-term purchased power is for wind, solar and storage resources." **Prior (2023):** 2022 Minnesota Electric Rate Case - In 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. In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/A In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows:•ALJ Report: March 31, 2023.•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. 1, 2022.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. 1, 2021. 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. 1, 2022.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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows: •ALJ Report: March 31, 2023. •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. 1, 2022. 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. 1, 2021. 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. 1, 2022. 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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. 30 30 30 Table of Contents Table of Contents 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.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and 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. 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 OperationsNSP-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 Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 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.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 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. **Current (2024):** 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. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In October 2023, the MPUC denied NSP-Minnesota's request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023. 2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota's request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024). Next steps in the procedural schedule are expected to be as follows: •Intervenor direct testimony: April 19, 2024 •Rebuttal testimony: May 24, 2024 •Evidentiary hearings: July 10-12, 2024 •ALJ Report: October 28, 2024 •MPUC Order Due: March 14, 2025 30 30 30 Table of Contents Table of Contents 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin's natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-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 AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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.Recently Concluded Regulatory ProceedingsWisconsin 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. 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.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. 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. --- ## Modified: Operating Cash Flows **Key changes:** - Reworded sentence: "31Cash provided by operating activities - 2022$3,932 Components of change - 2023 vs." **Prior (2023):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2021$2,189 Components of change - 2022 vs. 2021Higher net income139 Non-cash transactions257 Changes in working capital(300)Changes in net regulatory and other assets and liabilities 1,647 Cash provided by operating activities - 2022$3,932 Net cash provided by operating activities increased by $1,743 million for 2022 as compared to 2021. 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. **Current (2024):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2022$3,932 Components of change - 2023 vs. 2022Higher net income35 Non-cash transactions88 Changes in working capital900 Changes in net regulatory and other assets and liabilities 372 Cash provided by operating activities - 2023$5,327 Net cash provided by operating activities increased by $1,395 million for 2023 as compared to 2022. The increase was largely due to continued collections of prior year deferred net natural gas, fuel and purchased energy costs, as well as the impact of decreased natural gas prices on accounts payable and receivables. --- ## Modified: Major classes of property, plant and equipment **Key changes:** - Reworded sentence: "(Millions of Dollars)Dec." - Added sentence: "(a) 55 55 55 Table of Contents Table of Contents Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec." - Added sentence: "31, 2023:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 (a)Projects additionally include $2 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$178 $25 37 %CapX2020169 39 80 Total NSP-Wisconsin (a)$347 $64 (a)Projects additionally include $1 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $108 76 %Hayden Unit 2151 87 37 Hayden common facilities44 31 53 Craig Units 1 and 282 55 10 Craig common facilities39 25 7 Comanche Unit 3916 191 67 Comanche common facilities29 4 77 Electric transmission:Transmission and other facilities189 75 VariousGas transmission:Rifle, CO to Avon, CO28 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,643 $587 (a)Projects additionally include $18 million in CWIP.Each company's share of operating expenses and construction expenditures is included in the applicable utility accounts." - Added sentence: "Respective owners are responsible for providing their own financing." - Reworded sentence: "31, 2023:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 (a)Projects additionally include $2 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$178 $25 37 %CapX2020169 39 80 Total NSP-Wisconsin (a)$347 $64 (a)Projects additionally include $1 million in CWIP." **Prior (2023):** As of Dec. 31, 2022, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy's consolidated financial statements. 3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2022Dec. 31, 2021Property, plant and equipment, netElectric plant$49,639 $48,680 Natural gas plant8,514 7,758 Common and other property2,970 2,602 Plant to be retired (a)2,217 1,200 CWIP2,124 1,969 Total property, plant and equipment65,464 62,209 Less accumulated depreciation(17,502)(17,060)Nuclear fuel3,183 3,081 Less accumulated amortization(2,892)(2,773)Property, plant and equipment, net$48,253 $45,457 (a)Amounts as of Dec. 31, 2021 include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 1 and 2 and Craig Units 1 and 2 for PSCo; and Tolk and coal generation assets at Harrington pending facility gas conversion for SPS. Following the June 2022 approval of PSCo's revised resource plan settlement, amounts as of Dec. 31, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion as well as the removal of Comanche Unit 1 that was retired in 2022. Amounts are presented net of accumulated depreciation. Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec. 31, 2022:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$623 $468 59 %Sherco common facilities180 115 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 3 50 Huntley Wilmarth49 1 50 CapX2020818 124 51 Total NSP-Minnesota (a)$1,686 $715 (a)Projects additionally include $4 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$177 $20 37 %CapX2020166 34 80 Total NSP-Wisconsin (a)$343 $54 (a)Projects additionally include $1 million in CWIP. **Current (2024):** (Millions of Dollars)Dec. 31, 2023Dec. 31, 2022Property, plant and equipment, netElectric plant$52,494 $49,639 Natural gas plant9,080 8,514 Common and other property3,190 2,970 Plant to be retired (a)2,055 2,217 CWIP2,873 2,124 Total property, plant and equipment69,692 65,464 Less accumulated depreciation(18,399)(17,502)Nuclear fuel3,337 3,183 Less accumulated amortization(2,988)(2,892)Property, plant and equipment, net$51,642 $48,253 Plant to be retired (a) (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS. The Dec. 31, 2022 balance also includes Sherco 2, which was retired on Dec. 31, 2023. Amounts are presented net of accumulated depreciation. (a) 55 55 55 Table of Contents Table of Contents Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec. 31, 2023:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 (a)Projects additionally include $2 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$178 $25 37 %CapX2020169 39 80 Total NSP-Wisconsin (a)$347 $64 (a)Projects additionally include $1 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $108 76 %Hayden Unit 2151 87 37 Hayden common facilities44 31 53 Craig Units 1 and 282 55 10 Craig common facilities39 25 7 Comanche Unit 3916 191 67 Comanche common facilities29 4 77 Electric transmission:Transmission and other facilities189 75 VariousGas transmission:Rifle, CO to Avon, CO28 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,643 $587 (a)Projects additionally include $18 million in CWIP.Each company's share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec. 31, 2023:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 (a)Projects additionally include $2 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$178 $25 37 %CapX2020169 39 80 Total NSP-Wisconsin (a)$347 $64 (a)Projects additionally include $1 million in CWIP. --- ## Modified: Annual weather-normalized natural gas sales growth (decline) **Key changes:** - Reworded sentence: "•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." **Prior (2023):** •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. **Current (2024):** •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. --- ## Modified: New Technology and Government Grants **Key changes:** - Reworded sentence: "Hydrogen Hub Grant In October 2023, the DOE selected the Heartland Hydrogen Hub, including multiple clean hydrogen projects from Xcel Energy, for award negotiations to receive up to $925 million." - Removed sentence: "36 36 36 Table of Contents Table of Contents Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below." - Removed sentence: "Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions." - Removed sentence: "Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected." - Removed sentence: "Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows." **Prior (2023):** Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. 36 36 36 Table of Contents Table of Contents Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 2022 and 2021, Xcel Energy had regulatory assets of $3.9 billion and $3.8 billion, respectively and regulatory liabilities of $6.0 billion and $5.7 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2022, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information.Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized based on an evaluation of expected future taxable income. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.At Dec. 31, 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. 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. 31, 2022. This represents a 272 basis point and 271 basis point increase, respectively, from 2021. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 2022 and 2021, Xcel Energy had regulatory assets of $3.9 billion and $3.8 billion, respectively and regulatory liabilities of $6.0 billion and $5.7 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2022, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information. Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis. **Current (2024):** Hydrogen Hub Grant In October 2023, the 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 EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 2023 and 2022, Xcel Energy had regulatory assets of $3.4 billion and $3.9 billion, respectively and regulatory liabilities of $6.4 billion and $6.0 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2023, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information. --- ## Modified: Pending and Recently Concluded Regulatory Proceedings **Key changes:** - Reworded sentence: "2022 New Mexico Electric Rate Case - In 2022, SPS filed a New Mexico electric rate case seeking a revised revenue increase of $75 million." - Reworded sentence: "Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.OtherSupply Chain 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." - Reworded sentence: "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%)." - Reworded sentence: "SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost." **Prior (2023):** 2022 Minnesota Electric Rate Case - In 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. In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. 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)202220232024TotalRate request (annual increase)$234 $94 $170 $498 Rate base10,923 11,425 11,902 N/A In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows:•ALJ Report: March 31, 2023.•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. 1, 2022.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. 1, 2021. 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. 1, 2022.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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony. 202220232024NSP-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 Next steps in the procedural schedule are expected to be as follows: •ALJ Report: March 31, 2023. •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. 1, 2022. 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. 1, 2021. 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. 1, 2022. 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. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023. 30 30 30 Table of Contents Table of Contents 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.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and 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. 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 OperationsNSP-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 Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 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.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 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. **Current (2024):** 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. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In October 2023, the MPUC denied NSP-Minnesota's request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023. 2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota's request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024). Next steps in the procedural schedule are expected to be as follows: •Intervenor direct testimony: April 19, 2024 •Rebuttal testimony: May 24, 2024 •Evidentiary hearings: July 10-12, 2024 •ALJ Report: October 28, 2024 •MPUC Order Due: March 14, 2025 30 30 30 Table of Contents Table of Contents 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin's natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-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 AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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.Recently Concluded Regulatory ProceedingsWisconsin 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. 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.In October 2023, the MPUC issued an order approving NSP-Minnesota's application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.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. 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. --- ## Modified: CONSOLIDATED STATEMENTS OF INCOME **Key changes:** - Reworded sentence: "31202320222021Operating revenuesElectric$11,446 $12,123 $11,205 Natural gas2,645 3,080 2,132 Other115 107 94 Total operating revenues14,206 15,310 13,431 Operating expensesElectric fuel and purchased power4,278 5,005 4,733 Cost of natural gas sold and transported1,456 1,910 1,081 Cost of sales - other49 44 38 Operating and maintenance expenses2,444 2,491 2,321 Conservation and demand side management expenses286 331 304 Depreciation and amortization2,448 2,413 2,121 Taxes (other than income taxes)657 688 630 Loss on Comanche Unit 3 litigation35 - - Workforce reduction expenses72 - - Total operating expenses11,725 12,882 11,228 Operating income2,481 2,428 2,203 Other income (expense), net22 (13)5 Earnings from equity method investments35 36 62 Allowance for funds used during construction - equity91 75 73 Interest charges and financing costsInterest charges - includes other financing costs of $32, $31 and $29, respectively1,055 953 842 Allowance for funds used during construction - debt(51)(28)(26)Total interest charges and financing costs1,004 925 816 Income before income taxes1,625 1,601 1,527 Income tax benefit(146)(135)(70)Net income$1,771 $1,736 $1,597 Weighted average common shares outstanding:Basic552 547 539 Diluted552 547 540 Earnings per average common share:Basic$3.21 $3.18 $2.96 Diluted3.21 3.17 2.96 See Notes to Consolidated Financial Statements Interest charges - includes other financing costs of $32, $31 and $29, respectively 47 47 47 Table of Contents Table of Contents" **Prior (2023):** (amounts in millions, except per share data) Year Ended Dec. 31202220212020Operating revenuesElectric$12,123 $11,205 $9,802 Natural gas3,080 2,132 1,636 Other107 94 88 Total operating revenues15,310 13,431 11,526 Operating expensesElectric fuel and purchased power5,005 4,733 3,512 Cost of natural gas sold and transported1,910 1,081 689 Cost of sales - other44 38 37 Operating and maintenance expenses2,491 2,321 2,324 Conservation and demand side management expenses331 304 288 Depreciation and amortization2,413 2,121 1,948 Taxes (other than income taxes)688 630 612 Total operating expenses12,882 11,228 9,410 Operating income2,428 2,203 2,116 Other (expense) income, net(13)5 (6)Earnings from equity method investments36 62 40 Allowance for funds used during construction - equity75 73 115 Interest charges and financing costsInterest charges - includes other financing costs of $31, $29 and $28, respectively953 842 840 Allowance for funds used during construction - debt(28)(26)(42)Total interest charges and financing costs925 816 798 Income before income taxes1,601 1,527 1,467 Income tax benefit(135)(70)(6)Net income$1,736 $1,597 $1,473 Weighted average common shares outstanding:Basic547 539 527 Diluted547 540 528 Earnings per average common share:Basic$3.18 $2.96 $2.79 Diluted3.17 2.96 2.79 See Notes to Consolidated Financial Statements Interest charges - includes other financing costs of $31, $29 and $28, respectively 48 48 48 Table of Contents Table of Contents **Current (2024):** (amounts in millions, except per share data) Year Ended Dec. 31202320222021Operating revenuesElectric$11,446 $12,123 $11,205 Natural gas2,645 3,080 2,132 Other115 107 94 Total operating revenues14,206 15,310 13,431 Operating expensesElectric fuel and purchased power4,278 5,005 4,733 Cost of natural gas sold and transported1,456 1,910 1,081 Cost of sales - other49 44 38 Operating and maintenance expenses2,444 2,491 2,321 Conservation and demand side management expenses286 331 304 Depreciation and amortization2,448 2,413 2,121 Taxes (other than income taxes)657 688 630 Loss on Comanche Unit 3 litigation35 - - Workforce reduction expenses72 - - Total operating expenses11,725 12,882 11,228 Operating income2,481 2,428 2,203 Other income (expense), net22 (13)5 Earnings from equity method investments35 36 62 Allowance for funds used during construction - equity91 75 73 Interest charges and financing costsInterest charges - includes other financing costs of $32, $31 and $29, respectively1,055 953 842 Allowance for funds used during construction - debt(51)(28)(26)Total interest charges and financing costs1,004 925 816 Income before income taxes1,625 1,601 1,527 Income tax benefit(146)(135)(70)Net income$1,771 $1,736 $1,597 Weighted average common shares outstanding:Basic552 547 539 Diluted552 547 540 Earnings per average common share:Basic$3.21 $3.18 $2.96 Diluted3.21 3.17 2.96 See Notes to Consolidated Financial Statements Interest charges - includes other financing costs of $32, $31 and $29, respectively 47 47 47 Table of Contents Table of Contents --- ## Modified: Additional Information on Regulatory Authority **Key changes:** - Reworded sentence: "Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations." - Reworded sentence: "The ECA is revised quarterly.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC." **Prior (2023):** 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. **Current (2024):** Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market. Pipeline safety compliance. 32 32 32 Table of Contents Table of Contents Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer's bill.DecouplingMechanism 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 AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.ECARecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer's bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers 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 PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Pending and Recently Concluded Regulatory ProceedingsColorado 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 OwnedPPAsTotalWind Resources1,325 375 1,700 Solar858 760 1,618 Storage500 1,348 1,848 Natural Gas450 219 669 Total3,133 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. 31, 2023. PSCo has requested a proposed effective date of Nov. 1, 2024. 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)$145 Operations and maintenance, amortization and other expenses23 Property tax expense10 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. Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer's bill.DecouplingMechanism 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 AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.ECARecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer's bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers 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 PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Pending and Recently Concluded Regulatory ProceedingsColorado 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. --- ## Modified: Non-Fuel Operating Expenses and Other Items **Key changes:** - Reworded sentence: "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." - Reworded sentence: "and its nonregulated businesses:(Millions of Dollars)20232022Xcel Energy Inc." - Reworded sentence: "Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas." - Removed sentence: "Income Taxes - Income tax benefit increased $65 million year-to-date." - Removed sentence: "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." **Prior (2023):** 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; and other. 28 28 28 Table of Contents Table of Contents 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. 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 $65 million year-to-date. The year-to-date increase was primarily driven by an increase in wind PTCs due to greater production at existing wind farms, several new wind farms going into service and an increase in the PTC rate partially offset by higher pretax earnings. Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:Contribution (Millions of Dollars)20222021Xcel Energy Inc. financing costs$(153)$(129)Venture Holdings (a)5 21 Xcel Energy Inc. taxes and other results(12)(12)Total Xcel Energy Inc. and other costs$(160)$(120)Contribution (Diluted Earnings (Loss) Per Share)20222021Xcel Energy Inc. financing costs$(0.28)$(0.24)Venture Holdings (a)0.01 0.04 Xcel Energy Inc. taxes and other results(0.02)(0.02)Total Xcel Energy Inc. and other costs$(0.29)$(0.22)(a)Amounts include gains or losses associated with EIP investments.Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2021 Comparison with 2020 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2020 to Dec. 31, 2021 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2021, which was filed with the SEC on Feb. 23, 2022. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters within Note 12 to the consolidated financial statements for further information.NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.Reviews and approves natural gas supply plans.NDPSCRetail rates, services and other aspects of electric and natural gas operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.Pipeline safety compliance.SDPUCRetail rates, services and other aspects of electric operations.Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.MISONSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance. 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. 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 $65 million year-to-date. The year-to-date increase was primarily driven by an increase in wind PTCs due to greater production at existing wind farms, several new wind farms going into service and an increase in the PTC rate partially offset by higher pretax earnings. Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:Contribution (Millions of Dollars)20222021Xcel Energy Inc. financing costs$(153)$(129)Venture Holdings (a)5 21 Xcel Energy Inc. taxes and other results(12)(12)Total Xcel Energy Inc. and other costs$(160)$(120)Contribution (Diluted Earnings (Loss) Per Share)20222021Xcel Energy Inc. financing costs$(0.28)$(0.24)Venture Holdings (a)0.01 0.04 Xcel Energy Inc. taxes and other results(0.02)(0.02)Total Xcel Energy Inc. and other costs$(0.29)$(0.22)(a)Amounts include gains or losses associated with EIP investments.Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2021 Comparison with 2020 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2020 to Dec. 31, 2021 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2021, which was filed with the SEC on Feb. 23, 2022. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. 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. 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. **Current (2024):** 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 $102 million in 2023. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20232022Xcel Energy Inc. financing costs$(174)$(153)Venture Holdings (a)3 5 Xcel Energy Inc. taxes and other results(2)(12)Total Xcel Energy Inc. and other costs$(173)$(160)(Diluted Earnings (Loss) Per Share)20232022Xcel Energy Inc. financing costs$(0.32)$(0.28)Venture Holdings (a)0.01 0.01 Xcel Energy Inc. taxes and other results - (0.02)Total Xcel Energy Inc. and other costs$(0.31)$(0.29)(a)Amounts include gains or losses associated with EIP investments.Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2022 Comparison with 2021 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2021 to Dec. 31, 2022 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2022, which was filed with the SEC on Feb. 23, 2023. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas. 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. --- ## Modified: Changes in Diluted EPS **Key changes:** - Reworded sentence: "Components significantly contributing to changes in EPS: 2023 vs." **Prior (2023):** Components significantly contributing to changes in EPS: 2022 vs. 2021Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS - 2021$2.96 Components of change - 2022 vs. 2021Higher electric revenues, net of electric fuel and purchased power0.89 Higher natural gas revenues, net of cost of natural gas sold and transported0.16 Lower ETR (a)0.15 Higher depreciation and amortization(0.40)Higher O&M expenses(0.24)Higher interest expense(0.15)Higher taxes (other than income taxes)(0.08)Other (net)(0.12)GAAP and ongoing diluted EPS - 2022$3.17 Lower ETR (a) (a) Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to electric revenues. ROE for Xcel Energy and its utility subsidiaries: 20222021ROEGAAP and Ongoing ROEGAAP and Ongoing ROEPSCo8.23 %8.23 %NSP-Minnesota8.76 8.45 SPS9.36 9.22 NSP-Wisconsin10.57 9.92 Operating Companies8.74 8.58 Xcel Energy10.76 10.58 **Current (2024):** Components significantly contributing to changes in EPS: 2023 vs. 2022Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS - 2022$3.17 Components of change - 2023 vs. 2022Higher electric revenues, net of electric fuel and purchased power0.07 Lower O&M expenses0.06 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 transported0.03 Higher interest expense(0.14)Higher depreciation and amortization(0.05)Workforce reduction expenses(0.09)Loss on Comanche Unit 3 litigation(0.05)Other (net)0.06 GAAP diluted EPS - 2023$3.21 Workforce reduction expenses0.09 Loss on Comanche Unit 3 litigation0.05 Ongoing diluted EPS - 2023$3.35 ROE for Xcel Energy and its utility subsidiaries: 20232022ROEGAAP ROEOngoing ROEGAAP and Ongoing ROENSP-Minnesota8.82 %9.11 %8.76 %PSCo7.32 7.77 8.23 SPS9.80 9.98 9.36 NSP-Wisconsin10.38 10.67 10.57 Operating Companies8.45 8.79 8.74 Xcel Energy10.33 10.79 10.76 --- ## Modified: CONSOLIDATED BALANCE SHEETS **Key changes:** - Reworded sentence: "3120232022AssetsCurrent assetsCash and cash equivalents$129 $111 Accounts receivable, net1,315 1,373 Accrued unbilled revenues853 1,105 Inventories711 803 Regulatory assets611 1,059 Derivative instruments104 279 Prepaid taxes52 54 Prepayments and other294 360 Total current assets4,069 5,144 Property, plant and equipment, net51,642 48,253 Other assetsNuclear decommissioning fund and other investments3,599 3,234 Regulatory assets2,798 2,871 Derivative instruments76 93 Operating lease right-of-use assets1,217 1,204 Other678 389 Total other assets8,368 7,791 Total assets$64,079 $61,188 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$552 $1,151 Short-term debt785 813 Accounts payable1,668 1,804 Regulatory liabilities528 418 Taxes accrued557 569 Accrued interest251 217 Dividends payable289 268 Derivative instruments74 76 Operating lease liabilities226 217 Other722 545 Total current liabilities5,652 6,078 Deferred credits and other liabilitiesDeferred income taxes4,885 4,756 Deferred investment tax credits60 48 Regulatory liabilities5,827 5,569 Asset retirement obligations3,218 3,380 Derivative instruments86 113 Customer advances167 181 Pension and employee benefit obligations469 390 Operating lease liabilities1,038 1,038 Other148 147 Total deferred credits and other liabilities15,898 15,622 Commitments and contingenciesCapitalizationLong-term debt24,913 22,813 Common stock - 1,000,000,000 shares authorized of $2.50 par value; 554,941,703 and 549,578,018 shares outstanding at Dec." **Prior (2023):** (amounts in millions, except share and per share) Dec. 3120222021AssetsCurrent assetsCash and cash equivalents$111 $166 Accounts receivable, net1,373 1,018 Accrued unbilled revenues1,105 862 Inventories803 631 Regulatory assets1,059 1,106 Derivative instruments279 123 Prepaid taxes54 44 Prepayments and other360 289 Total current assets5,144 4,239 Property, plant and equipment, net48,253 45,457 Other assetsNuclear decommissioning fund and other investments3,234 3,628 Regulatory assets2,871 2,738 Derivative instruments93 67 Operating lease right-of-use assets1,204 1,291 Other389 431 Total other assets7,791 8,155 Total assets$61,188 $57,851 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$1,151 $601 Short-term debt813 1,005 Accounts payable1,804 1,409 Regulatory liabilities418 271 Taxes accrued569 569 Accrued interest217 209 Dividends payable268 249 Derivative instruments76 69 Operating lease liabilities217 205 Other545 459 Total current liabilities6,078 5,046 Deferred credits and other liabilitiesDeferred income taxes4,756 4,894 Deferred investment tax credits48 53 Regulatory liabilities5,569 5,405 Asset retirement obligations3,380 3,151 Derivative instruments113 105 Customer advances181 196 Pension and employee benefit obligations390 306 Operating lease liabilities1,038 1,146 Other147 158 Total deferred credits and other liabilities15,622 15,414 Commitments and contingenciesCapitalizationLong-term debt22,813 21,779 Common stock - 1,000,000,000 shares authorized of $2.50 par value; 549,578,018 and 544,025,269 shares outstanding at Dec. 31, 2022 and Dec. 31, 2021, respectively1,374 1,360 Additional paid in capital8,155 7,803 Retained earnings7,239 6,572 Accumulated other comprehensive loss(93)(123)Total common stockholders' equity16,675 15,612 Total liabilities and equity$61,188 $57,851 See Notes to Consolidated Financial Statements Common stock - 1,000,000,000 shares authorized of $2.50 par value; 549,578,018 and 544,025,269 shares outstanding at Dec. 31, 2022 and Dec. 31, 2021, respectively 51 51 51 Table of Contents Table of Contents **Current (2024):** (amounts in millions, except share and per share) Dec. 3120232022AssetsCurrent assetsCash and cash equivalents$129 $111 Accounts receivable, net1,315 1,373 Accrued unbilled revenues853 1,105 Inventories711 803 Regulatory assets611 1,059 Derivative instruments104 279 Prepaid taxes52 54 Prepayments and other294 360 Total current assets4,069 5,144 Property, plant and equipment, net51,642 48,253 Other assetsNuclear decommissioning fund and other investments3,599 3,234 Regulatory assets2,798 2,871 Derivative instruments76 93 Operating lease right-of-use assets1,217 1,204 Other678 389 Total other assets8,368 7,791 Total assets$64,079 $61,188 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$552 $1,151 Short-term debt785 813 Accounts payable1,668 1,804 Regulatory liabilities528 418 Taxes accrued557 569 Accrued interest251 217 Dividends payable289 268 Derivative instruments74 76 Operating lease liabilities226 217 Other722 545 Total current liabilities5,652 6,078 Deferred credits and other liabilitiesDeferred income taxes4,885 4,756 Deferred investment tax credits60 48 Regulatory liabilities5,827 5,569 Asset retirement obligations3,218 3,380 Derivative instruments86 113 Customer advances167 181 Pension and employee benefit obligations469 390 Operating lease liabilities1,038 1,038 Other148 147 Total deferred credits and other liabilities15,898 15,622 Commitments and contingenciesCapitalizationLong-term debt24,913 22,813 Common stock - 1,000,000,000 shares authorized of $2.50 par value; 554,941,703 and 549,578,018 shares outstanding at Dec. 31, 2023 and Dec. 31, 2022, respectively1,387 1,374 Additional paid in capital8,465 8,155 Retained earnings7,858 7,239 Accumulated other comprehensive loss(94)(93)Total common stockholders' equity17,616 16,675 Total liabilities and equity$64,079 $61,188 See Notes to Consolidated Financial Statements Common stock - 1,000,000,000 shares authorized of $2.50 par value; 554,941,703 and 549,578,018 shares outstanding at Dec. 31, 2023 and Dec. 31, 2022, respectively 50 50 50 Table of Contents Table of Contents --- ## Modified: Change in Natural Gas Margin **Key changes:** - Reworded sentence: "(Millions of Dollars)2023 vs." **Prior (2023):** (Millions of Dollars)2022 vs. 2021Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, North Dakota)$61 Estimated impact of weather46 Conservation revenue (offset in expenses)13 Infrastructure and integrity riders9 Winter Storm Uri disallowances(20)Other (net)10 Total increase$119 **Current (2024):** (Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (CO, WI, MI)$50 Estimated impact of weather (net of decoupling)(25)Other (net)(6)Total increase$19 --- ## Modified: Financing Cash Flows **Key changes:** - Reworded sentence: "31Cash provided by financing activities - 2022$666 Components of change - 2023 vs." - Added sentence: "40 40 40 Table of Contents Table of Contents" **Prior (2023):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2021$2,135 Components of change - 2022 vs. 2021Lower debt issuances(1,159)Higher repayments of long-term debt(184)Lower proceeds from issuance of common stock(44)Higher dividends paid to shareholders(77)Other financing activities(5)Cash provided by financing activities - 2022$666 Net cash provided by financing activities decreased by $1,469 million for 2022 as compared to 2021. The decrease was primarily related to the amount/timing of debt issuances and repayments associated with Winter Storm Uri.See Note 5 to the consolidated financial statements for further information.Capital RequirementsXcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy's financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, 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. Net cash provided by financing activities decreased by $1,469 million for 2022 as compared to 2021. The decrease was primarily related to the amount/timing of debt issuances and repayments associated with Winter Storm Uri. See Note 5 to the consolidated financial statements for further information. **Current (2024):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2022$666 Components of change - 2023 vs. 2022Higher debt issuances, net of repayments80 Lower proceeds from issuance of common stock(52)Higher dividends paid to shareholders(80)Other financing activities3 Cash provided by financing activities - 2023$617 Net cash provided by financing activities decreased by $49 million for 2023 as compared to 2022. The decrease was largely related to the amount/timing of debt issuances and repayments. See Note 5 to the consolidated financial statements for further information. 40 40 40 Table of Contents Table of Contents --- ## Modified: 2023 Comparison with 2022 **Key changes:** - Reworded sentence: "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." - Reworded sentence: "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." **Prior (2023):** 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 Inc. and Other - Earnings decreased $0.07 per share year-to-date due to higher interest charges and decreased earnings from EIP investments. 26 26 26 Table of Contents Table of Contents Changes in Diluted EPSComponents significantly contributing to changes in EPS:2022 vs. 2021Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS - 2021$2.96 Components of change - 2022 vs. 2021Higher electric revenues, net of electric fuel and purchased power0.89 Higher natural gas revenues, net of cost of natural gas sold and transported0.16 Lower ETR (a)0.15 Higher depreciation and amortization(0.40)Higher O&M expenses(0.24)Higher interest expense(0.15)Higher taxes (other than income taxes)(0.08)Other (net)(0.12)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.ROE for Xcel Energy and its utility subsidiaries:20222021ROEGAAP and Ongoing ROEGAAP and Ongoing ROEPSCo8.23 %8.23 %NSP-Minnesota8.76 8.45 SPS9.36 9.22 NSP-Wisconsin10.57 9.92 Operating Companies8.74 8.58 Xcel Energy10.76 10.58 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. 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. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity.HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather.Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2022 vs.Normal2021 vs.Normal2022 vs. 2021HDD6.5 %(6.6)%13.0 %CDD23.7 12.2 16.1 THI5.6 26.8 (15.8)Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2022 vs. Normal2021 vs. Normal2022 vs. 2021Retail electric$0.138 $0.096 $0.042 Decoupling and sales true-up(0.061)(0.066)0.005 Electric total$0.077 $0.030 $0.047 Firm natural gas0.037 (0.025)0.062 Total$0.114 $0.005 $0.109 Sales - Sales growth (decline) for actual and weather-normalized sales:2022 vs. 2021PSCoNSP-MinnesotaSPSNSP-WisconsinXcel EnergyActualElectric residential(1.5)%(1.2)%6.5 %1.1 %(0.1)%Electric C&I - 1.7 8.9 3.3 3.3 Total retail electric sales(0.5)0.8 8.4 2.6 2.3 Firm natural gas sales5.4 18.3 N/A17.3 10.1 2022 vs. 2021PSCoNSP-MinnesotaSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(3.6)%(0.2)%0.8 % - %(1.3)%Electric C&I(0.3)2.1 8.4 3.4 3.2 Total retail electric sales(1.4)1.3 6.9 2.4 1.8 Firm natural gas sales(3.1)5.5 N/A5.8 0.1 Changes in Diluted EPSComponents significantly contributing to changes in EPS:2022 vs. 2021Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS - 2021$2.96 Components of change - 2022 vs. 2021Higher electric revenues, net of electric fuel and purchased power0.89 Higher natural gas revenues, net of cost of natural gas sold and transported0.16 Lower ETR (a)0.15 Higher depreciation and amortization(0.40)Higher O&M expenses(0.24)Higher interest expense(0.15)Higher taxes (other than income taxes)(0.08)Other (net)(0.12)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.ROE for Xcel Energy and its utility subsidiaries:20222021ROEGAAP and Ongoing ROEGAAP and Ongoing ROEPSCo8.23 %8.23 %NSP-Minnesota8.76 8.45 SPS9.36 9.22 NSP-Wisconsin10.57 9.92 Operating Companies8.74 8.58 Xcel Energy10.76 10.58 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. 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. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity.HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. **Current (2024):** 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 - 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 EPSComponents significantly contributing to changes in EPS:2023 vs. 2022Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS - 2022$3.17 Components of change - 2023 vs. 2022Higher electric revenues, net of electric fuel and purchased power0.07 Lower O&M expenses0.06 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 transported0.03 Higher interest expense(0.14)Higher depreciation and amortization(0.05)Workforce reduction expenses(0.09)Loss on Comanche Unit 3 litigation(0.05)Other (net)0.06 GAAP diluted EPS - 2023$3.21 Workforce reduction expenses0.09 Loss on Comanche Unit 3 litigation0.05 Ongoing diluted EPS - 2023$3.35 ROE for Xcel Energy and its utility subsidiaries:20232022ROEGAAP ROEOngoing ROEGAAP and Ongoing ROENSP-Minnesota8.82 %9.11 %8.76 %PSCo7.32 7.77 8.23 SPS9.80 9.98 9.36 NSP-Wisconsin10.38 10.67 10.57 Operating Companies8.45 8.79 8.74 Xcel Energy10.33 10.79 10.76 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy's financial performance. However, electric decoupling mechanisms in Colorado (mechanism expired in September 2023) and electric sales true-up mechanisms in Minnesota and gas decoupling mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in those jurisdictions. Xcel Energy Inc. and Other - Primarily includes financing costs and interest income at the holding company and earnings from EIP funds equity method investments. Fluctuations from 2022 levels were largely attributable to increased interest rates. --- *Data sourced from SEC EDGAR. Last updated 2026-06-01.*