XCEL ENERGY INC
For the period ended Mar 31, 2025. Filed Apr 24, 2025.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2025 · Filed Apr 24, 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-Q
Period ended 2024-09-30; filed 2024-10-31.
0000072903-24-000199
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-03-31; filed 2025-04-24.
0000072903-25-000088
Item 2. 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 284 previous paragraphs and 256 current paragraphs.
152 unchanged; 57 reworded; 46 added; 65 removed; 10 previous and 1 current paragraphs rearranged.
Tables are not compared: 26 previous and 20 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 (46)
Current report
PSCo— GAAP and ongoing earnings increased $0.06 per share for the first quarter of 2025. The change was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and interest charges.
Current report
NSP-Minnesota— GAAP and ongoing earnings decreased $0.06 per share for the first quarter of 2025. The change was driven by increased O&M expenses and depreciation, partially offset by higher recovery of electric and natural gas infrastructure investments.
Current report
(a)Cost of electric fuel and purchased power and natural gas sold and transported are generally recovered through regulatory recovery mechanisms and offset in revenue.
Current report
Natural gas sold and transported increased $30 million for the first quarter of 2025. The increase was primarily due to higher volumes and commodity prices, partially offset by timing of fuel recovery mechanisms.
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
In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. The procedural schedule is as follows:
Current report
•Intervenor direct testimony: August 22, 2025
Current report
•ALJ Report: April 30, 2026
Current report
•MPUC Decision: July 31, 2026
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
Wisconsin Electric and Natural Gas Rate Case– In March 2025, NSP-Wisconsin filed a request with the PSCW for a multi-year electric and natural gas rate increase.
Current report
For the electric utility, NSP-Wisconsin is seeking a total electric revenue increase of $94 million (11.8%) in 2026 and an incremental $57 million (7.1%) in 2027, for a total of $151 million over the two-year period of 2026 and 2027. The electric rate increase is based on electric rate base of $2.9 billion in 2026 and $3.2 billion in 2027. For the natural gas utility, NSP-Wisconsin requested a total natural gas revenue increase of $20 million (12.7%) in 2026 and an incremental $4 million (1.5%) in 2027, for a total of $24 million (14.2%) over the two-year period of 2026 and 2027. The natural gas rate increase is based on natural gas rate base of $0.3 billion in 2026 and $0.4 billion in 2027. Both the electric and natural gas rate requests are based on forward-looking test years, with a 10.0% ROE and an equity ratio of 53.5%.
Current report
The rate request is primarily driven by investments in NSP-Wisconsin’s electric and natural gas systems to enhance reliability and resiliency while ensuring safe operation. The investments also enable additional clean energy generation; the benefits of wind, solar and nuclear tax credits are incorporated in the table below.
Current report
A PSCW decision is anticipated in the fourth quarter of 2025.
Current report
(a)The Interchange Agreement is a FERC cost sharing tariff under which NSP-Wisconsin and its affiliate, NSP-Minnesota allocate the costs of the integrated electric generation and transmission system.
Current report
In February 2025, the MPUC approved the terms of the settlement agreement, including:
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
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. The CPUC held deliberations in April 2025 and did not order changes to the approved annual revenue increase. A written decision remains pending.
Current report
In December 2023, the CPUC approved a framework for PIMs associated with the generation projects in the portfolio. In September 2024, PSCo filed a proposal for implementation of the PIMs. In April 2025, PSCo filed an unopposed settlement, which establishes key details of the various symmetrical PIMs. Key terms include:
Current report
•A cost-to-construct PIM, in which costs over or under a deadband will be used to calculate a PIM to be shared with customers over 10 years, beginning after the in-service date.
Current report
•An operational PIM on wind and solar projects based on annual weather-normalized, curtailment-adjusted energy amounts, subject to a cap of approximately $8 million per year.
Current report
•An availability PIM on new gas generation approved in the resource plan, subject to a cap of $1 million per year.
Current report
A CPUC decision on the settlement is expected by the third quarter of 2025.
Current report
In April 2025, PSCo filed with the CPUC a comprehensive and unanimous settlement. Key terms include:
Current report
•Approval of the updated WMP, including scope of mitigation activities and the Public Safety Power Shutoffs plan, with certain modifications.
Current report
•Cost recovery of proposed investments through a Wildfire Mitigation Adjustment rider and recovery of transmission investments through the Transmission Cost Adjustment rider.
Current report
•PSCo agrees to request approval to pursue securitization of an estimated $1.2 billion of proposed WMP investments, with a target to complete the transaction by Jan. 1, 2029.
Current report
•Extension of the excess liability insurance deferral, with a cap of $50 million after PSCo’s current policy year, which ends October 2025.
Current report
A CPUC decision is expected by the third quarter of 2025.
Current report
In December 2024, the CPUC adopted final rules applicable to PSCo’s natural gas utility that would assign to the Company four percent of the change in the price per MMbtu of natural gas compared to the three-year average, subject to rolling 12-month cap based on a percentage of rate base, currently estimated at $7 million. The rules require PSCo to make a filing to implement the mechanism within sixty days of becoming effective, expected later in 2025.
Current report
In December 2024, the CPUC also adopted rules for electric utilities but did not adopt a specific PIM framework, which will be further considered through additional proceedings in 2025.
Current report
Texas System Resiliency Plan— In December 2024, SPS filed its Texas SRP with the PUCT. Consistent with PUCT requirements, SPS’ proposed plan discusses resiliency-related risks and the five measures that have been designed to help SPS prevent, withstand, mitigate or more promptly recover from resiliency events, including wildfire.
Current report
The proposed SRP covers 2025-2028 and includes a proposed $538 million of investment across the following measures:
Current report
•Distribution overhead hardening — Replacing and reinforcing key components of the distribution overhead system.
Current report
•Distribution system protection modernization — Installing enhanced reclosers, communications equipment and replacing substation relay panels and breakers.
Current report
•Communication modernization — Building out a private LTE network, installing fiber optic cable and adding remote terminal units.
Current report
•Operational flexibility — Procuring mobile substation equipment and installing additional switching devices.
Current report
•Wildfire mitigation — Weather stations, modeling, deploying artificial intelligence and vegetation management.
Current report
In April 2025, SPS filed a unanimous stipulation and settlement agreement which includes approximately $490 million of spend over the plan period, adjusted largely to reflect the removal of the operational flexibility measure for investment in the normal course of business. The settlement also includes the deferral of distribution-related costs, including depreciation expense and carrying costs at SPS’ weighted average cost of capital.
Showing the first 40 of 46 passages. Open the source sections for the rest.
Removed paragraphs (65)
Previous report
The following table provides a reconciliation of GAAP earnings (net income to ongoing earnings:
Previous 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 October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage.
Previous report
Comanche Unit 3 Litigation — As a result of an Oct. 25, 2023 jury verdict in Denver County District Court awarding CORE lost power damages and other costs, PSCo recognized a $34 million loss for the matter in the third quarter of 2023. Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings.
Previous report
NSP-Minnesota— GAAP earnings decreased $0.02 per share and ongoing earnings increased 0.02 per share for the third quarter. Year-to-date GAAP earnings increased $0.11 per share and ongoing earnings increased $0.17 per share. Year-to-date earnings primarily reflect increased recovery of infrastructure investments (electric and natural gas), partially offset by higher depreciation and interest charges. See Note 6 for reconciliation from GAAP to ongoing earnings.
Previous report
PSCo— GAAP earnings increased $0.04 per share and ongoing earnings increased $0.01 per share for the third quarter. Year-to-date GAAP earnings increased $0.09 per share and ongoing earnings increased $0.04 per share. Year-to-date ongoing earnings primarily reflect higher recovery of electric infrastructure investments, which was partially offset by increased interest charges, depreciation and O&M expenses.
Previous report
(a)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs.
Previous report
Natural gas sold and transported decreased $7 million for the third quarter and $420 million year-to-date. The decrease is primarily due to lower commodity prices and volumes.
Previous report
Other Income— Other income increased $36 million for the third quarter and $56 million year-to-date. The year-to-date increase was primarily due to interest earned and rabbi trust performance, which is partially offset in O&M expenses.
Previous report
AFUDC, Equity and Debt— AFUDC increased $25 million for the third quarter and $71 million year-to-date, driven by increased investment in renewable and transmission projects.
Previous report
In October 2024, an ALJ recommended the MPUC approve the rate case settlement. A MPUC decision and order is expected in the first quarter of 2025.
Previous report
In August 2024, NSP-Minnesota filed a settlement agreement with NDPSC Staff and AARP. Key terms of the settlement included an increase in natural gas rates of $7.3 million (8.1%), based on a ROE of 9.9% and an equity ratio of 52.5%.
Previous report
A NDPSC decision and order is expected by the end of 2024.
Previous report
Nuclear Power Operations
Previous report
Michigan Electric Rate Case —In July 2024, NSP-Wisconsin filed a Michigan electric rate case, seeking a $2.9 million (16.7%) rate increase for 2025, based on a ROE of 10.0% and an equity ratio of 52%. In addition, NSP-Wisconsin proposed an Investment Recovery Mechanism which would result in increases of $2.0 million (9.8%) in 2026 and $0.8 million (3.7%) in 2027 for recovery of costs associated with distribution and generation investment. A decision is expected in the first half of 2025.
Previous report
Wisconsin 2025 Stay-Out Proposal — In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW. The filing proposes to offset 2025 revenue deficiencies of $28 million for electric and $3 million for natural gas, 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. NSP-Wisconsin expects to have a PSCW decision by year-end 2024.
Previous report
•In the second quarter of 2023, NSP-Minnesota initiated the process with the MPUC for acquisition of firm dispatchable resources. In October 2024, a settlement was reached with various parties, pending MPUC approval. See below for more details.
Previous report
NSP-Minnesota anticipates a MPUC decision in 2025 and will file a RFP for remaining resource needs upon approval. The settlement included the following key items:
Previous report
Based on the CPUC order, PSCo estimates an annual revenue increase of approximately $130 million, inclusive of $15 million of accelerated depreciation, with rates expected to be effective Nov. 5, 2024.
Previous report
•Situational awareness— Meteorology, area risk mapping and modeling, artificial intelligence cameras and continuous monitoring.
Previous report
•Operational mitigations – Enhanced powerline safety settings and PSPS.
Previous report
•System resiliency— Asset assessment and remediations, pole replacements, line rebuilds, targeted undergrounding and vegetation management.
Previous report
•Customer support— Coordination and real-time data sharing with customers and other stakeholders and PSPS resiliency rebates.
Previous report
The CPUC requested that PSCo file supplemental testimony including the impacts of potential securitization of the proposed wildfire mitigation plan investments. Total capital investments and O&M expenses associated with the proposed plan are estimated at the following:
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•Answer testimony: Feb. 14, 2025
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•Decision deadline: Aug. 28, 2025
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CPUC Proactive Line De-Energization Investigation— In April 2024, PSCo proactively de-energized certain lines in Colorado due to winds that were over 90 miles per hour to reduce potential wildfire risk.
Previous report
The CPUC opened a docket related to the proactive de-energizing of power lines to evaluate potential improvements to the process. The CPUC plans to continue evaluation of PSCo’s policies for proactive line de-energizations through its ongoing review of the 2025-2027 wildfire mitigation plan and, in the interim, will require PSCo to file additional information to the CPUC, hold work sessions with emergency responders, test customer communication protocols, and provide monthly progress updates to the CPUC.
Previous report
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 report
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 gas cost adjustment 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 report
In October 2024, the CPUC also issued a proposed PIM for electric utilities. Similar to the natural gas PIM, it would determine any incentive/penalty by comparing the year-over-year change in the price of natural gas procured for electric generation. PSCo filed comments in October 2024 and a hearing is expected to occur in November 2024. A CPUC decision is expected by the end of 2024.
Previous report
Colorado Senate Bill 24-218 — In May 2024, Colorado Senate Bill 24-218 was signed into law. The bill includes a suite of policy changes to accelerate investment in electric distribution, including a framework to develop distribution planning and performance requirements and the opportunity for current cost recovery through a rider for distribution investments. In July 2024, the CPUC approved PSCo’s request to collect $17 million through a rider, over the remainder of 2024, subject to true-up, associated with forecasted capital investments covered by the new legislation. PSCo expects to file an updated 2025 rider in November 2024.
Previous report
Cabin Creek Prudency Review —In 2015, the CPUC granted a CPCN for an $88 million upgrade project to increase the generating and storage capacity of the Cabin Creek hydroelectric storage facility, which anticipated project completion in 2020. Due to significant and unforeseen challenges, the project was not completed until 2023 and cost approximately $110 million. In July 2024, PSCo filed a prudency review for the upgrade project, which reviews the project’s timelines, costs, benefits and challenges.
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Procedural schedule:
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•Answer testimony: Feb. 3, 2025
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•Settlement testimony: April 4, 2025
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•Hearing: April 17-18, 2025
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A final CPUC decision is expected in the second quarter of 2025.
Previous report
Excess Liability Insurance Deferral — In August 2024, PSCo filed a request with the CPUC to establish a tracker to defer differences in excess liability insurance premiums after the October 2024 policy renewal (reflecting significantly rising premiums, largely associated with wildfire risks throughout the United States) and amounts currently recovered. In October 2024, the CPUC approved an accelerated procedural schedule which is as follows:
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•Rebuttal testimony: Nov. 1, 2024
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•Settlement deadline: Nov. 12, 2024
Showing the first 40 of 65 passages. Open the source sections for the rest.
Reworded paragraphs (57)
Previous wording
Xcel Energy — Xcel Energy’s third quarter GAAP earnings were $1.21 per share, compared with $1.19 per share in the same period in 2023 and ongoing earnings were $1.25 per share in 2024, compared with $1.23 per share in 2023. The change in earnings per share was primarily driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).
Current wording
Xcel Energy — Xcel Energy’s first quarter GAAP and ongoing diluted earnings were $0.84 per share compared with $0.88 per share in the same period in 2024. The change in earnings per share was primarily driven by higher O&M expenses, depreciation and interest charges, partially offset by increased recovery of infrastructure investments. 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).
Previous wording
SPS— GAAP and ongoing earnings increased $0.01 per share for the third quarter of 2024 and $0.03 year-to-date. Year-to-date earnings reflect the impact of regulatory rate outcomes and sales growth, partially offset by increased depreciation and O&M expenses.
Current wording
SPS— GAAP and ongoing earnings were flat for the first quarter of 2025 largely due to higher recovery of electric infrastructure investments and sales growth, offset by increased depreciation and O&M expenses.
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NSP-Wisconsin— GAAP and ongoing earnings increased $0.01 per share for the third quarter of 2024 and year-to-date. Year-to-date earnings reflect the impact of electric infrastructure investment recoveries, partially offset by higher depreciation and interest expenses.
Current wording
NSP-Wisconsin— GAAP and ongoing earnings decreased $0.01 per share for the first quarter of 2025. The change was driven by higher O&M expenses, depreciation and interest charges.
Previous 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 is largely due to increased interest rates and higher debt levels.
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 was largely due to higher debt levels and the performance of the equity method investments, which primarily invest in energy technology companies.
Previous wording
Changes in GAAP and Ongoing Diluted EPS
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Changes in GAAP and Ongoing EPS
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As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric sales true-up and gas decoupling mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.
Current wording
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.
Previous wording
Percentage increase (decrease) in normal and actual HDD, CDD and THI:
Current wording
Percentage increase (decrease) in normal and actual HDD:
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•PSCo — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by customer growth of 1.4%. The C&I sales decline was related to decreased use per customer, primarily in the information sector.
Current wording
•PSCo — Residential sales increased due to customer growth of 1.4%, partially offset by a 0.3% decrease in use per customer. The C&I sales decline was related to lower use per customer, primarily in the wholesale trade and transportation sectors.
Previous wording
•NSP-Minnesota — Residential sales declined due to a 2.2% decrease in use per customer, partially offset by a 1.5% increase in customers. C&I sales declined due to decreased use per customer, largely in the manufacturing, retail trade and education sectors.
Current wording
•NSP-Minnesota — Residential sales increased due to customer growth of 1.2% and a 0.1% increase in use per customer. C&I sales increased due to customer growth and higher use per customer, largely in the manufacturing sector.
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•SPS — Residential sales declined as a result of a 2.2% decrease in use per customer, partially offset by 0.6% customer growth. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining.
Current wording
•SPS — Residential sales increased as a result of a 3.7% increase in use per customer and customer growth of 0.8%. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
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•NSP-Wisconsin — Residential sales declined due to a 3.2% decrease in use per customer, partially offset by 0.9% increase in customers. C&I sales decline was associated with decreased use per customer, experienced largely in the manufacturing and professional services sectors.
Current wording
•NSP-Wisconsin — Residential sales increased due to a 2.0% increase in use per customer and customer growth of 1.0%. C&I sales increased due to customer growth, experienced largely in the professional services and manufacturing sectors.
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•Increase in natural gas sales was driven by residential and C&I customer growth in all jurisdictions and increased residential use per customer in PSCo offset by decreased use per customer in PSCo C&I and other jurisdictions.
Current wording
•Increase in natural gas sales was driven primarily by residential and C&I customer growth in all jurisdictions and higher residential use per customer in NSP-Minnesota and NSP-Wisconsin. This was offset by decreased use per customer in PSCo residential and NSP-Minnesota C&I.
Previous wording
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.
Current wording
Electric Fuel and Purchased Power— Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
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Electric fuel and purchased power expenses decreased $121 million for the third quarter and $465 million year-to-date. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices.
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Electric fuel and purchased power expenses increased $72 million for the first quarter of 2025. The increase was primarily due to increased volumes and commodity prices partially offset by timing of fuel recovery mechanisms.
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O&M Expenses — O&M expenses increased $69 million for the third quarter and increased $58 million year-to-date. The year-to-date increase was primarily due to operational activities (generation maintenance, damage prevention, storm response and wildfire mitigation) and recognition of previously deferred costs associated with the Texas Electric Rate Case, partially offset by gain on land sale in the first quarter and lower bad debt expense.
Current wording
O&M Expenses — O&M expenses increased $81 million for the first quarter of 2025. The increase was primarily due to operational activities, including higher nuclear generation costs and distribution system maintenance (vegetation management, storm response and wildfire mitigation), the impact of a 2024 gain on land sale and increased insurance and benefits costs.
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Depreciation and Amortization— Depreciation and amortization increased $63 million for the third quarter and $235 million year-to-date. The year-to-date increase was largely the result of system expansion partially offset by recognition of previously deferred costs and depreciation rate changes associated with various rate cases.
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Depreciation and Amortization— Depreciation and amortization increased $70 million for the first quarter of 2025. The increase was largely the result of system investment as well as depreciation rate updates through regulatory proceedings.
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Interest Charges— Interest charges increased $57 million for the third quarter and $146 million year-to-date, largely due to increased debt levels and higher interest rates.
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Interest Charges— Interest charges increased $41 million for the first quarter of 2025, largely due to increased debt levels and higher interest rates.
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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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In February 2025, the MPUC verbally approved the uncontested settlement agreement filed by NSP-Minnesota and various parties, which includes the following terms:
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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. The appeal is pending a court decision expected in the first quarter of 2025.
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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.
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2024 Minnesota Electric Rate Case — In early November 2024, NSP-Minnesota plans to file 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 will also request interim rates of $224 million to go into effect in January 2025. A decision is expected in 2026.
Current wording
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.
Previous wording
2024 North Dakota Natural Gas Rate Case— In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In February 2024, the NDPSC approved interim rates of $8 million, effective 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). A NDPSC decision is expected in late 2025.
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2024 Upper Midwest Resource Plan —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 targeted resource additions for the 5-year Action Plan and the process under which those resources will be secured, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition.
Current wording
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.
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•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 June and July 2024 RFPs). Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line.
Current wording
•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.
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2022 Upper Midwest IRP Resource Acquisition —NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.
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NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.
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•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 by the fourth quarter of 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
•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 expect to announce short listed projects in December 2024 and plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second quarter of 2025.
Current wording
•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. 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.
Previous wording
In October 2024, the CPUC issued an order including the following key decisions:
Current wording
In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including the following key decisions:
Previous wording
In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a PIM related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in related proceedings throughout 2024. In September 2024, PSCo filed a proposed framework for CPUC review of pricing adjustments for both company owned and PPA resources to enable delivery of the approved portfolio in light of supply chain and geopolitical developments. A decision is expected in the fourth quarter of 2024.
Current wording
In September 2024, PSCo filed a proposed framework for CPUC review of pricing adjustments for both company owned and PPA resources to enable delivery of the approved portfolio in light of supply chain and geopolitical developments. In January 2025, the CPUC issued a decision granting limited potential pricing relief including potential tariff impacts, subject to evaluation in future CPCN proceedings for company owned projects.
Previous wording
PSCo filed or expects to file generation and transmission CPCNs throughout 2024 and early 2025.
Current wording
PSCo filed or expects to file generation and transmission CPCNs throughout 2024 and 2025.
Previous wording
2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its electric resource plan, known as the Just Transition Solicitation, with the CPUC. The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources.
Current wording
2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its electric resource plan with the CPUC. The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources.
Previous wording
The procedural schedule is as follows:
Current wording
Answer testimony was received in April 2025. The remaining procedural schedule is as follows:
Previous wording
Wildfire Mitigation Plan —In June 2024, PSCo filed an updated WMP and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion. A CPUC decision is expected in the third quarter of 2025.
Current wording
Wildfire Mitigation Plan —In June 2024, PSCo filed an updated WMP and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion.
Previous wording
The WMP is a key component of keeping our customers and communities safe while providing reliable and affordable electric service. The WMP integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner under four core programs that include the following:
Current wording
The WMP integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner.
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. In September 2024, the CPUC issued a recommended decision in adopting rules to implement a natural gas PIM prior to Jan. 1, 2025. Per the recommended decision, natural gas costs incurred will be compared to the prior year to determine any incentive/penalty. In October 2024, PSCo filed targeted exceptions. A final decision is expected in fourth quarter of 2024.
Current wording
Colorado Senate Bill 23-291 — In May 2023, Colorado Senate Bill 23-291 was signed into law. The legislation included a number of topics including for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers.
Previous wording
The RFP will be evaluated in the first quarter of 2025. SPS is expected to file for a certificate of need for the recommended portfolio in the summer of 2025. The Texas and New Mexico Commissions are expected to rule on the portfolio in 2026.
Current wording
Bids from the RFP were received in January and are currently being evaluated. A portfolio selection filing is expected in the second quarter of 2025 followed by a certificate of need filing for the specific assets in the third quarter of 2025. The PUCT and NMPRC are expected to rule on the portfolio in 2026.
Previous wording
Large global demand for energy-related infrastructure (renewables and gas generation, data centers, etc.) has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability.
Current wording
Large global demand for energy-related infrastructure has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability.
Previous wording
Xcel Energy’s ability to meet customer energy requirements, execute our capital expenditure program and respond to storm-related disruptions 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.
Current wording
In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work.
Previous wording
In October 2024, the U.S. Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact Xcel Energy projects. A preliminary decision related to the anti-dumping portion of the matter is anticipated in November 2024.
Current wording
In April 2025, the U.S. Department of Commerce announced its final determination in the countervailing duty circumvention and anti-dumping investigations. The rates will go into effect after the U.S. International Trade Commission makes its final determination, expected in the second quarter of 2025. Xcel Energy does not expect these determinations to impact its projects.
Previous wording
Xcel Energy continues to assess the impacts of these tariffs and trade complaints on its business, including company-owned projects and PPAs. Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions.
Current wording
Xcel Energy continues to assess the impacts of these tariffs, executive orders, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief, if required, in its jurisdictions.
Previous wording
Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs.
Current wording
Continued and/or further policy actions or other restrictions, disruptions in imports from key suppliers, or any new trade complaint could impact viability, timelines and costs of various projects and PPAs.
Showing the first 40 of 57 pairs. Open the source sections for the rest.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
Xcel Energy’s ability to meet customer energy requirements and growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain.
Rearranged previous paragraphs (10)
Previous report — wording carried elsewhere
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023 for further information. The circumstances set forth in Nuclear Power Operations included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023, appropriately represent, in all material respects, the current status of nuclear power operations.
Previous report — wording carried elsewhere
Xcel Energy 2024 Earnings Guidance— Xcel Energy’s 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.(a)
Previous report — wording carried elsewhere
•Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk.
Previous report — wording carried elsewhere
•Normal weather patterns for the remainder of the year.
Previous report — wording carried elsewhere
•Weather-normalized retail electric sales are projected to increase ~1%.
Previous report — wording carried elsewhere
•Weather-normalized retail firm natural gas sales are projected to decline by ~1%.
Previous report — wording carried elsewhere
•O&M expenses are projected to increase 3% to 4%.
Previous report — wording carried elsewhere
Key assumptions as compared with 2024 projected levels unless noted:
Previous report — wording carried elsewhere
•Capital rider revenue is projected to increase $240 million to $250 million (net of PTCs).
Previous report — wording carried elsewhere
•Interest expense (net of AFUDC - debt) is projected to increase $130 million to $140 million, net of interest income.