XCEL ENERGY INC
For the period ended Dec 31, 2024. Filed Feb 27, 2025.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 27, 2025
XEL$79.67-0.9%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-02-21.
0000072903-24-000034
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-27.
0000072903-25-000029
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 362 previous paragraphs and 375 current paragraphs.
176 unchanged; 92 reworded; 105 added; 88 removed; 6 previous and 2 current paragraphs rearranged.
Tables are not compared: 42 previous and 41 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (105)
Current report
Adjustments to GAAP net income include:
Current report
Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In 2024, following contested case procedures, Xcel Energy recognized a customer refund of $47 million for replacement power incurred during the outage.
Current report
Electric Revenues
Current report
Natural Gas Revenues
Current report
Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.
Current report
Electric fuel and purchased power expenses decreased $490 million in 2024. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices, partially offset by increased volumes.
Current report
Natural gas sold and transported decreased $505 million in 2024. The decrease is primarily due to lower commodity prices and volumes.
Current report
O&M Expenses — O&M expenses increased $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention. The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially offset by lower labor and benefit costs and lower bad debt expenses.
Current report
Other Income— Other income increased $121 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gain on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation.
Current report
AFUDC, Equity and Debt—AFUDC increased $99 million in 2024. This increase was largely due to increased investment in renewable and transmission projects.
Current report
(a)Amounts include gain from open market debt repurchases in 2024.
Current report
•Natural gas rate increase of $46 million, or 7.5%.
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•ROE of 9.6%.
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•Equity ratio of 52.5%.
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•Rate base of $1.25 billion.
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•No change to Commission approved decoupling.
Current report
In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.
Current report
2024 North Dakota Natural Gas Rate Case— In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million.
Current report
In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025.
Current report
In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.
Current report
In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.
Current report
2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.
Current report
In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.
Current report
Pending Regulatory Proceedings
Current report
Michigan Electric Rate Case —In July 2024, NSP-Wisconsin filed a Michigan electric rate case with the MPSC. In December 2024, the MPSC approved NSP-Wisconsin’s settlement agreement. The settlement order includes an electric rate increase of $1.75 million in 2025 and a step increase of $0.55 million in 2026, based on a ROE of 9.8% and an equity ratio of 50%.
Current report
Wisconsin 2025 Stay-Out Proposal — In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW. In December 2024, the PSCW approved NSP-Wisconsin’s filing, which offsets $27 million in electric deficiencies and $3 million in natural gas deficiencies by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two natural gas capital projects.
Current report
Excess Liability Insurance Deferral –In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal. A PSCW decision is expected in the third quarter of 2025.
Current report
Resource Acquisition —In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC. In October 2024, NSP-Minnesota filed a settlement with several parties reaching agreement on the resource plan, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition.
Current report
In February 2025, the MPUC verbally approved the terms of the settlement agreement, including:
Current report
•The selection of the company owned 420 MW Lyon County combustion turbine.
Current report
•The selection of the company owned 300 MW 4-hour Sherco battery energy storage system.
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•Multiple PPAs to proceed to the negotiation stage.
Current report
•The addition of 3,200 MW of wind, 400 MW of solar and 600 MW of stand-alone storage to be added through 2030 based on an RFP process (a portion of which is expected to be fulfilled with the resources acquired as part of the 2024 RFPs). Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line.
Current report
Additionally, the MPUC approved life extensions of the Red Wing and Mankato RDF plants to 2037 and ordered NSP-Minnesota to file a proposed tariff for customers with super-large load, largely data centers, by July 15, 2025.
Current report
NSP-Minnesota will file additional RFPs for approved resource needs beginning in late 2025 or early 2026.
Current report
NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.
Current report
•In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit. Bids are currently under evaluation; NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025 and plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second half of 2025.
Current report
In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including the following key decisions:
Current report
•Use of a historic 2023 test year, with a 13-month average rate base.
Current report
•Acceleration of $15 million per year of depreciation expense (incremental to PSCo’s original rate request), to be held in an external trust for future decommissioning costs.
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Removed paragraphs (88)
Previous report
(a)Amounts may not add due to rounding.
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(a)Amounts may not add due to rounding.
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Electric Margin
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Electric Revenues, Fuel and Purchased Power and Electric Margin
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Change in Electric Margin
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(a)Sales excludes weather impact, net of partial decoupling in Colorado (mechanism expired in September 2023) and sales true-up mechanism in Minnesota.
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(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.
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Natural Gas Margin
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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.
Previous report
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin
Previous report
Change in Natural Gas Margin
Previous report
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.
Previous report
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.
Previous report
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.
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(a)Amounts include gains or losses associated with EIP investments.
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(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.
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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.
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Next steps in the procedural schedule are expected to be as follows:
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•Intervenor direct testimony: April 19, 2024
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•Evidentiary hearings: July 10-12, 2024
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•ALJ Report: October 28, 2024
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•MPUC Order Due: March 14, 2025
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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.
Previous report
Recently Concluded Regulatory Proceedings
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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.
Previous report
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.
Previous report
2022 Upper Midwest IRP Resource Acquisition —Following the MPUC’s approval of NSP-Minnesota and NSP-Wisconsin’s latest IRP in April 2022, NSP-Minnesota and NSP-Wisconsin have been engaged in multiple resource acquisition processes and proceedings to meet the need identified in the IRP for the NSP System.
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•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.
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•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.
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•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.
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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:
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•Reduced carbon emissions by more than 80%, potentially up to 88%, by 2030.
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•Adds 3,600 MW of new wind and solar resources by 2030.
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•Adds 600 MW of battery energy storage by 2030.
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•Adds more than 2,200 MW of dispatchable resources by 2030.
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NSP-Minnesota anticipates a MPUC decision in 2025.
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Colorado Electric Rate Case —In 2022, PSCo filed a Colorado electric rate case seeking a revised net increase of $253 million. The total request reflected a $303 million increase, which includes $50 million of authorized costs previously recovered through various rider mechanisms. The request was based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of $11.3 billion.
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•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.
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•Termination of the revenue decoupling pilot.
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•Continuation of previously authorized trackers and deferrals.
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Reworded paragraphs (92)
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We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted earnings per share, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP.
Current wording
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted EPS, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP.
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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.
Current wording
Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a non-recurring $34 million charge as a result of a jury verdict in Denver County District Court awarding CORE Electric Cooperative lost power damages and other costs.
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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.
Current wording
Workforce Reduction —In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs and streamline the organization for long-term success. Xcel Energy initiated a Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program. Workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023.
Previous wording
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.
Current wording
Xcel Energy — GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023. The change in EPS was driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses.
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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.
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NSP-Minnesota— GAAP earnings increased $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation and interest charges.
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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.
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PSCo— GAAP earnings increased $0.13 per share and ongoing earnings increased $0.06 per share for 2024. Higher ongoing earnings primarily reflects higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation, O&M and interest charges.
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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.
Current wording
SPS — GAAP earnings were flat and ongoing earnings decreased $0.01 per share for 2024. Ongoing earnings were impacted by increased depreciation, O&M and interest charges, largely offset by regulatory rate outcomes and sales growth.
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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.
Current wording
NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 per share for 2024. The decrease in ongoing earnings was primarily a result of higher depreciation.
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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.
Current wording
Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings for 2024 is largely due to higher debt levels and increased interest rates, partially offset by a gain on debt repurchases.
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Components significantly contributing to changes in EPS:
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Components significantly contributing to changes in 2024 EPS compared with 2023:
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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.
Current wording
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 sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.
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Annual weather-normalized electric sales growth (decline)
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Annual weather-normalized and leap year adjusted electric sales growth (decline)
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•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.
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•NSP-Minnesota — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers. The decline in C&I sales was due to lower use per customer, particularly in the manufacturing sector.
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•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.
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•PSCo — Residential sales increased due to a 1.4% increase in customers, partially offset by a 0.7% decrease in use per customer. The decline in C&I sales was attributable to decreased use per customer, particularly in the wholesale trade and mining.
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•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.
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•SPS — Residential sales declined due to a 2.2% decrease in use per customer partially offset by a 0.7% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining.
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•NSP-Wisconsin — The C&I sales decline was associated with lower use per customer, experienced primarily in the transportation and manufacturing sectors.
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•NSP-Wisconsin — Residential sales declined due to a 2.7% decrease in use per customer, offset by a 1.0% increase in customers. The C&I sales decline was associated with lower use per customer, experienced particularly in the professional services and manufacturing sectors.
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Annual weather-normalized natural gas sales growth (decline)
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Annual weather-normalized and leap year adjusted natural gas sales growth (decline)
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•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.
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•Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases. Partially offsetting these were increased residential and C&I customers in all jurisdictions.
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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.
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Electric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes.
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Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms.
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Electric Fuel and Purchased Power— Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
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Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
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Cost of Natural Gas Sold and Transported— Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
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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.
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Depreciation and Amortization—Depreciation and amortization increased $296 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions.
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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.
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Interest Charges— Interest charges increased $200 million in 2024. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.
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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).
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2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%.
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In September 2023, the CPUC approved a settlement between PSCo and various parties, which included the following terms:
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In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms:
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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.
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2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC.
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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.
Current wording
2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).
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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.
Current wording
Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.
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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.
Current wording
Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.
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In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.
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In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.
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•Extends the operation of Prairie Island and Monticello nuclear plants through the early 2050s.
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•Planned life extensions of the Prairie Island and Monticello nuclear plants through the early 2050s.
Previous wording
•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.
Current wording
•In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023. NSP-Minnesota expects to file for approval of recommended projects in summer 2025.
Previous wording
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.
Current wording
Colorado Natural Gas Rate Case —In January 2024, PSCo, filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million (9.5%). The request was based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year and a $4.2 billion year-end rate base.
Previous wording
•Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).
Current wording
•Weighted-average cost of capital of 7.0%, based on an ROE range of 9.2%-9.5% and an equity ratio range of 52%-55%.
Previous wording
Rates went into effect in October 2023.
Current wording
PSCo placed new rates into effect in November, as modified on ARRR in February 2025, with an annual revenue increase of approximately $125 million, inclusive of $15 million of accelerated depreciation. The UCA filed a second ARRR in February 2025, which remains pending.
Previous wording
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.
Current wording
In December 2023, the CPUC approved a framework for two PIMs associated with the generation projects in the portfolio — a PIM related to capital construction costs and another related to ongoing levelized energy costs with details to be further defined via subsequent proceedings throughout 2024. In September 2024, PSCo filed a proposal for implementation of the PIMs. Intervenor testimony is due Feb. 27, 2025, with a final decision expected in summer 2025.
Previous wording
Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).
Current wording
Colorado Senate Bill 23-291 — In May 2023, Colorado Senate Bill 23-291 was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).
Previous wording
In November 2023, the CPUC approved PSCo’s natural gas price risk management plan, establishing upper and lower limits for changes in the GCA rate. As a result costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit are deferred as a reserve against future cost increases.
Current wording
In November 2023, the CPUC approved PSCo’s natural gas price risk plan to manage customer bill volatility from commodity price changes, establishing upper and lower limits for changes in the GCA rate. As a result, costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit deferred as a reserve against future cost increases.
Previous wording
The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. The CPUC issued a request for initial comments on a potential mechanism under which gas utilities would share a percentage, subject to an annual cap, of cost changes in the GCA. A formal rulemaking is expected to commence in the first half of 2024.
Current wording
The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers.
Previous wording
•A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction.
Current wording
•A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction and in other proceedings filed before the PUCT where a stated WACC is required.
Showing the first 40 of 92 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
Xcel Energy’s ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain.
Current report — wording carried from elsewhere
Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.
Rearranged previous paragraphs (6)
Previous report — wording carried elsewhere
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.
Previous report — wording carried elsewhere
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.
Previous report — wording carried elsewhere
As a result, changes in these expenses are generally offset in operating revenues.
Previous report — wording carried elsewhere
•The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028.
Previous report — wording carried elsewhere
See Note 11 to the consolidated financial statements for further information.
Previous report — wording carried elsewhere
See Note 12 to the consolidated financial statements for further information.