XCEL ENERGY INC
For the period ended Mar 31, 2026. Filed Apr 30, 2026.
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, 2026 · Filed Apr 30, 2026
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 2025-09-30; filed 2025-10-30.
0000072903-25-000257
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-04-30.
0000072903-26-000073
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 279 previous paragraphs and 230 current paragraphs.
127 unchanged; 58 reworded; 44 added; 88 removed; 6 previous and 1 current paragraphs rearranged.
Tables are not compared: 29 previous and 21 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 (44)
Current report
Prairie Island Outage Refunds —In March 2026, the ALJ recommended a disallowance of $41 million for estimated replacement power costs incurred during a 2023-2024 outage at NSP-Minnesota’s Prairie Island nuclear facility. A non-recurring charge of $37 million was recorded to electric revenues in the first quarter of 2026 for incremental customer refunds, including interest.
Current report
Marshall Wildfire Litigation— In the first quarter of 2026, PSCo recognized a $22 million reduction to operating expenses due to an increase in the estimated amount recoverable from insurance for non-recurring Marshall Wildfire costs.
Current report
PSCo— GAAP earnings decreased $0.03 per share and ongoing earnings decreased $0.06 per share for the first quarter of 2026. The change was driven by unfavorable weather, which was partially offset by higher recovery of electric infrastructure investments. The difference between GAAP and ongoing earnings was driven by the increase in estimated Marshall Wildfire insurance amounts recoverable.
Current report
SPS— GAAP and ongoing earnings increased $0.03 per share for the first quarter of 2026. The change was driven by sales growth, partially offset by increased depreciation expense and unfavorable weather.
Current report
•Residential sales — Decrease is due to lower use per customer in SPS (6.1%) and PSCo (2.5%), partially offset by customer growth in all jurisdictions.
Current report
•C&I sales — Increase is due to higher use per customer in SPS (10.6%) and NSP-Minnesota (1.8%) and customer growth in NSP-Wisconsin (1.1%). Increased activity in the energy sector in SPS and various sectors in all jurisdictions contributed to the sales growth.
Current report
O&M Expenses — O&M expenses decreased $11 million for the first quarter of 2026. The change was primarily due to lower benefits and bad debt expenses.
Current report
On April 29, 2026, the ALJ report was issued. NSP-Minnesota estimates that the ALJ recommendation would result in a rate increase of approximately $248 million, based on a ROE of 9.8% and an equity ratio of 52.5%.
Current report
A MPUC decision is expected in the third quarter of 2026.
Current report
In March 2026, the DOC, OAG and CUB filed direct testimony and recommended financial adjustments. The DOC recommended a total rate increase of $31 million, and an ROE of 9.3%. The OAG and CUB provided limited comments, with the OAG recommending a reduction of approximately $6 million in O&M expenses and CUB recommending an ROE of 9.0%.
Current report
Next steps in the procedural schedule are as follows:
Current report
•Surrebuttal testimony: May 1, 2026
Current report
•ALJ Report: September 1, 2026
Current report
A MPUC decision is expected in November 2026.
Current report
•In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued an RFP seeking up to 3,500 MW of wind, solar, hydro, standalone storage, or hybrid capacity that will achieve commercial operation by December 31, 2030. Additionally, NSP-Minnesota is seeking to procure up to 600 MW of solar or solar plus storage capacity that will achieve commercial operation by December 31, 2029, and meet Minnesota’s Distributed Solar Energy Standard eligibility requirements. Bids were submitted in March 2026, and filing for requisite regulatory approval is expected by the end of 2026.
Current report
Large Load Agreement —In the first quarter of 2026, NSP-Minnesota entered into an electric service agreement to power a new Google data center in Minnesota. Under the agreement, Google will pay all costs for its new service for the duration of the agreement, in accordance with Minnesota’s regulatory and legislative requirements for large loads. If approved, the agreement is expected to result in approximately $1.1 billion of benefits to NSP-Minnesota’s customers. A request for approval of the Electric Service Agreement, including a proposed Clean Energy Accelerator Charge for 1,900 MW of clean energy resources, was filed with the MPUC in April 2026. Approvals for 1,000 MW of resources for the Clean Energy Accelerator program are pending as part of existing resource acquisition processes. The remaining resources are expected to be requested in those processes by the end of 2026.
Current report
2025 Colorado Electric Rate Case —In November 2025, PSCo filed an electric rate case with the CPUC seeking an increase in revenue of $356 million (9.9%) ($526 million inclusive of rider roll-ins). The request is based on a 9.8% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $13 billion.
Current report
On April 28, 2026, eight intervenors filed testimony, with CPUC Staff, UCA, and CEC filing comprehensive testimony. The FEA additionally proposed certain financial adjustments.
Current report
The following modifications were proposed:
Current report
The remaining procedural schedule is as follows::
Current report
•Settlement deadline: May 28, 2026
Current report
•Hearing: June 11-18, 2026
Current report
A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.
Current report
•Answer testimony: June 5, 2026
Current report
•Rebuttal testimony: July 2, 2026
Current report
•Settlement deadline: July 8, 2026
Current report
•Hearing: July 23-30, 2026
Current report
A CPUC decision and implementation of final rates is anticipated in the fourth quarter of 2026.
Current report
PSCo filed a request for reconsideration of various aspects of the decision which were approved in February 2026. This decision is expected to initiate the Phase II competitive solicitation process with an RFP expected to be issued in the third quarter of 2026. This RFP will seek to acquire the balance of resource needs through 2031 (after consideration of any approved acquisitions from the Near-Term Procurement RFP).
Current report
In February 2026, the CPUC approved 3,200 MW of resources, which included PPAs and a 200 MW company-owned natural gas combustion turbine. In April 2026, the CPUC verbally approved an additional 600 MW company-owned wind facility.
Current report
2025 New Mexico Electric Rate Case— In November 2025, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $168 million (16.0%) as updated in March 2026. The request is based on a future test year period ending Nov. 30, 2027, a ROE of 10.5%, an equity ratio of 56% and retail rate base of $3.9 billion.
Current report
•Rebuttal testimony: May 29, 2026
Current report
•Public Evidentiary Hearing: July 7, 2026
Current report
A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2026.
Current report
Large Load/Data Center Tariffs
Current report
In several of our jurisdictions, we have proposed tariffs applicable to large load customers. These tariffs are designed to allow us to serve these new customers and support local economic development while protecting existing customers from bearing the incremental costs to serve these loads.
Current report
While the details of these tariffs vary by jurisdiction, they generally include provisions to ensure data center customers pay the incremental costs to serve them, minimum demand or revenue requirements, termination or exit fees and customer security provisions. These tariffs and contracts are subject to approval by state regulatory commissions. The status of the filings in each jurisdiction is as follows.
Current report
NSP-Minnesota —The proposed tariff, filed in the third quarter of 2025, would be mandatory for new loads over 100 MW and includes an incremental cost test, minimum initial term of 15 years, minimum bill provisions, termination and exit fees, and credit requirements. A MPUC decision is expected in the second quarter of 2026.
Current report
PSCo — The proposed tariff, filed in the second quarter of 2026, would be mandatory for new loads over 50 MW and requires the customer pay for generation and other infrastructure costs needed to serve the load. The proposed tariff also includes a minimum initial term of 15 years, minimum bill provisions, termination and exit fees, and credit requirements. A CPUC decision is expected in late 2026 or early 2027.
Current report
Similar large load tariff requests are expected to be filed in Wisconsin, New Mexico, and Texas in the second quarter of 2026.
Showing the first 40 of 44 passages. Open the source sections for the rest.
Removed paragraphs (88)
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, which is presented as a non-recurring charge to electric revenues.
Previous report
Marshall Wildfire Litigation— In the third quarter of 2025, PSCo recognized a non-recurring $287 million charge as a result of a settlement reached with the plaintiffs in the Marshall Wildfire litigation.
Previous report
NSP-Minnesota— GAAP earnings increased $0.08 per share and ongoing earnings increased$0.04 for the third quarter. Year-to-date GAAP earnings increased $0.11 per share and ongoing earnings increased$0.05 per share. The year-to-date ongoing earnings increase was driven by higher recovery of electric infrastructure investments, which was partially offset by increased O&M expenses, depreciation and interest charges.
Previous report
SPS— GAAP and ongoing earnings decreased $0.04 per share for the third quarter and decreased $0.03 year-to-date. The year-to-date change was driven by unfavorable weather, increased interest charges and O&M expenses, partially offset by higher recovery of electric infrastructure investments and sales growth.
Previous 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.
Previous report
•NSP-Minnesota — Residential sales increased due to customer growth (1.1%) and increase in use per customer (0.4%). C&I sales decreased due to lower use per customer.
Previous report
•PSCo — Residential sales increased due to increased use per customer (1.6%) and customer growth (1.2%). C&I sales increased due to higher use per customer and customer growth, primarily in the information and energy sectors.
Previous report
•SPS — Residential sales increased due to higher use per customer (4.1%) and customer growth (0.7%). C&I sales increased due to higher use per customer, primarily driven by the energy sector.
Previous report
•NSP-Wisconsin — Residential sales increased due to both increased use per customer (1.1%) and customer growth (1.0%).
Previous report
Electric fuel and purchased power expenses increased $38 million for the third quarter of 2025 and $173 million year-to-date. The year-to-date increase was primarily due to increased commodity prices and transmission expense partially offset by decreased volumes and timing of fuel recovery mechanisms.
Previous report
O&M Expenses — O&M expenses increased $37 million for the third quarter of 2025 and $131 million year-to-date. The year-to-date increase was primarily due to increased benefits and healthcare costs, nuclear generation costs and insurance costs.
Previous report
Other Income— Other income increased $7 million for the third quarter of 2025 and $46 million year-to-date, largely due to gains on debt repurchases in the second quarter of 2025.
Previous report
2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC.
Previous 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.
Previous report
(b)Riverside Generating Plant experienced a mechanical failure in April 2025 that resulted in an extended outage.
Previous report
Positions on NSP-Minnesota’s filed rate request:
Previous report
An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.
Previous report
On July 8, 2025, two intervenors filed testimony with a range of recommendations. NDPSC Staff recommended an increase of approximately $30 million, with a 9.41% ROE and a 50% equity ratio, along with other proposed adjustments that were not quantified. NSP-Minnesota estimates the NDPSC Staff recommendation would result in a rate increase of $20 million to $25 million. A NDPSC decision is expected in early 2026.
Previous report
NSP-Wisconsin
Previous 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. The PSCW verbally approved the request in August 2025.
Previous 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.
Previous 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%.
Previous report
On August 8, 2025, the PSCW Staff and intervenors filed their direct testimony. The PSCW Staff recommended an electric base rate increase of $115 million or 14.4% over the two-year period. The PSCW Staff additionally recommended a natural gas rate increase of $21 million, or 12.3% over the two-year period, all based on a ROE of 9.7% and an equity ratio of 53.5%.
Previous report
Intervenors mainly limited their comments on revenue requirements to ROE focusing the majority of their testimony on cost of service, rate design and other policy issues.
Previous report
The major components of the PSCW Staff recommendation are summarized below:
Previous report
(a)Capital investment adjustment includes $7 million associated with two MISO LRTP projects that are pending PSCW approval (Grid Forward and Western Wisconsin Transmission Connection). It is PSCW Staff historic practice to recommend adjustments for projects until Commission approval is received. Approval of both LRTP projects is anticipated in the fourth quarter of 2025.
Previous report
(b)Since filing the case, the Minnesota Public Utilities Commission authorized a reduction to the annual nuclear decommissioning accrual. This reduction, which flows to NSP-Wisconsin through the interchange agreement, reduced the NSP-Wisconsin rate request and is earnings neutral.
Previous report
A PSCW decision is anticipated in the fourth quarter of 2025.
Previous report
Michigan Natural Gas Rate Case– In July 2025, NSP-Wisconsin filed a natural gas rate case in Michigan, seeking a revenue increase of $2.2 million. An MPSC decision is expected in early 2026.
Previous report
In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including the following key decisions:
Previous report
•Use of a historic 2023 test year, with a 13-month average rate base.
Previous report
•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%.
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•Acceleration of $15 million per year of depreciation expense (incremental to PSCo’s original rate request), to potentially be held in an external trust for future decommissioning costs.
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•Modifications to recoverability of certain operating expenses.
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•Denial of PSCo’s decoupling proposal.
Previous 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. In May 2025, PSCo filed an appeal with the Denver District Court seeking review of the CPUC’s decisions related to recovery of certain operating expenses, cost of capital and capital structure, and the treatment of gas storage inventory costs. Briefing will be completed in the fourth quarter of 2025.
Previous report
Colorado Resource Plan — In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs.
Previous report
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. In September 2025, the CPUC authorized the process for company-owned and PPA resources to seek up to 15% relief for tariff impacts to projects. Relief requests are due by Dec. 31, 2025 or 18 months prior to COD. The CPUC will ultimately review and approve/deny requests.
Previous report
PSCo has filed all generation CPCNs associated with company-owned generation from the Colorado Energy Plan and expects to continue filing transmission CPCNs throughout 2025 and 2026.
Previous report
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.
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Reworded paragraphs (58)
Previous wording
Xcel Energy’s third quarter GAAP diluted earnings were $0.88 per share compared with $1.21 per share in the same period in 2024 and ongoing earnings were $1.24 compared with $1.25 per share in 2024. The change in ongoing earnings per share was primarily driven by higher depreciation, interest charges and O&M expenses 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).
Current wording
Xcel Energy’s first quarter GAAP earnings were $0.89 per share compared with $0.84 per share in the same period in 2025 and ongoing earnings were $0.91 compared with $0.84 per share in 2025. Despite the impact of unseasonably warm weather in the first quarter, ongoing earnings per share was primarily driven by increased recovery of electric infrastructure investments and electric sales growth, partially offset by higher financing costs and increased depreciation expense. 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
PSCo— GAAP earnings decreased $0.37 per share and ongoing earnings decreased $0.01 for the third quarter of 2025. Year-to-date GAAP earnings decreased $0.27 and ongoing earnings increased $0.09. The year-to-date ongoing earnings increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and interest charges.
Current wording
NSP-Minnesota— GAAP earnings decreased $0.02 per share and ongoing earnings increased $0.02 per share for the first quarter of 2026. The ongoing earnings increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased interest charges. The difference between GAAP and ongoing earnings was driven by recognition of customer refunds related to the 2023-2024 Prairie Island nuclear facility outage.
Previous wording
NSP-Wisconsin— GAAP and ongoing earnings per share were flat for the third quarter of 2025 and year-to-date. The year-to-date change was driven by higher recovery of electric and natural gas infrastructure investments, which was offset by increased depreciation and O&M expenses.
Current wording
NSP-Wisconsin— GAAP and ongoing earnings increased $0.03 per share for the first quarter of 2026. The change was driven by higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation expense.
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 change in earnings was largely due to gains on debt repurchases, partially offset by higher interest rates and debt levels and the performance of the equity method investments, which primarily invest in energy technology companies.
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.
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(b)Amounts may not add due to rounding.
Current wording
(a)Amounts may not add due to rounding.
Previous 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.
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.
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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(a)The sales true-up mechanism in NSP-Minnesota expired in 2024 and is proposed in the pending Minnesota electric rate case to be reestablished in 2026.
Current wording
(a)The sales true-up mechanism in NSP-Minnesota is proposed in the pending Minnesota electric rate case to be reestablished in 2026.
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Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date
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Weather-normalized electric sales growth (decline)— year-to-date
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Weather-normalized and leap-year adjusted natural gas sales growth (decline)— year-to-date
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Weather-normalized natural gas sales growth (decline)— year-to-date
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•Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential, partially offset by growth in other jurisdictions.
Current wording
•Increase in natural gas sales was driven primarily by customer growth in all jurisdictions, partially offset by decreased use per customer for C&I and residential customers in PSCo and NSP-Wisconsin.
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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 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.
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. Electric fuel and purchased power expenses decreased $1 million for the first quarter of 2026.
Previous wording
Natural gas sold and transported decreased $2 million for the third quarter of 2025 and increased $44 million year-to-date. The year-to-date increase was primarily due to higher commodity prices and volumes, partially offset by timing of fuel recovery mechanisms.
Current wording
Natural gas sold and transported increased $7 million for the first quarter of 2026. The change was primarily due to higher commodity prices partially offset by decreased volumes in PSCo.
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Depreciation and Amortization— Depreciation and amortization increased $69 million for the third quarter of 2025 and $158 million year-to-date. The year-to-date increase was largely the result of system investment.
Current wording
Depreciation and Amortization— Depreciation and amortization increased $40 million for the first quarter of 2026. The change was largely the result of system investment.
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Interest Charges— Interest charges increased $58 million for the third quarter of 2025 and $129 million year-to-date, largely due to higher debt levels and interest rates.
Current wording
Interest Charges— Interest charges increased $80 million for the first quarter of 2026, largely due to higher debt levels and interest rates.
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AFUDC, Equity and Debt— AFUDC increased $50 million for the third quarter of 2025 and $112 million year-to-date, largely the result of system investment.
Current wording
AFUDC, Equity and Debt— AFUDC increased $61 million for the first quarter of 2026, largely the result of system investment.
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In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. XLI recommended $190 million in proposed adjustments, based on a reduced ROE and a reduction in certain O&M expenses. CUB recommended proposed adjustments based on a reduced ROE and elimination of reconnection and late fee revenues. Walmart recommended an adjustment based on a reduced ROE. Other parties provided issue specific recommendations.
Current wording
In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations.
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In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota’s proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers.
Current wording
In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota’s proposed adjustments, approximately $100 million relates to depreciation expense and about $50 million is expected to be addressed through trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%.
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Proposed DOC modifications to NSP-Minnesota’s request are summarized below:
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Proposed ALJ modifications to NSP-Minnesota’s request were as follows:
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2025 Minnesota Natural Gas Rate Case— On Oct. 31, 2025, NSP-Minnesota plans to file a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota will also request interim rates of $51 million to go into effect on Jan. 1, 2026. As part of the request, NSP-Minnesota plans to file an option for a stay-out alternative.
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2025 Minnesota Natural Gas Rate Case— In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $62 million (8.2%) as updated in April 2026. The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC.
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In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.
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2022 Minnesota Electric Rate Case — In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%.
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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. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with the procedural schedule expected to be established in the fourth quarter of 2025.
Current wording
NSP-Minnesota appealed certain aspects of the MPUC decision. In January 2025, the Minnesota Court of Appeals issued its opinion, which included reversing and remanding decisions related to executive compensation and prepaid pension asset back to the MPUC. In March 2026, the MPUC declined to modify the treatment of executive compensation. A commission decision on prepaid pension asset is expected in mid-2026.
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2025 South Dakota Electric Rate Case — In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. NSP-Minnesota will request interim rates to begin on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.
Current wording
2025 South Dakota Electric Rate Case — In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, an equity ratio of 52.87% and rate base of approximately $1.2 billion. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.
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A SDPUC decision is expected in the second quarter of 2026.
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In April 2026, NSP-Minnesota and SDPUC Staff filed a black box settlement agreement with the SDPUC, including a net annual electric rate increase of $26 million. A SDPUC decision is expected in the second quarter of 2026.
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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).
Current wording
2026 North Dakota Natural Gas Rate Case— In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. In March 2026, the NDPSC approved interim rates of $12 million effective April 1, 2026.
Previous 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 early 2026.
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. NSP-Minnesota filed for approval of recommended projects in March 2026.
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. 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 fourth 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 retirement of Sherco and A.S King coal units. NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025. NSP-Minnesota received MPUC approval of the selected resources in March 2026 and NSP-Wisconsin expects to file for approvals with the PSCW in the second quarter of 2026.
Previous wording
•NSP-Minnesota and NSP-Wisconsin will continue to file additional RFPs throughout 2025 and 2026 for resource needs approved as part of the 2024 Upper Midwest Resource Plan.
Current wording
•NSP-Minnesota and NSP-Wisconsin may continue to file additional RFPs throughout 2026 and 2027 for resource needs as part of its Upper Midwest resource planning efforts.
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 (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.
Current wording
2025 Colorado Natural Gas Rate Case —In December 2025, PSCo filed a natural gas rate case with the CPUC seeking an increase in revenue of $190 million (11.6%). The request is based on a 10.75% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $4.7 billion.
Previous wording
•The plan also presents a low sales forecast with a 3% compound annual sales growth through 2031.
Current wording
2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its Phase I electric resource plan with the CPUC. In November 2025, the CPUC approved a load forecast that reflects a 3% compound annual sales growth through 2031 and generation capacity need of approximately 5,400 MW.
Previous wording
Near-Term Procurement —In August 2025, PSCo filed a joint motion with state agencies to initiate a “fast-tracked” solution for tax-advantaged new generation resources. The CPUC approved the request in September 2025 with bids submitted in October 2025. The procurement seeks to accelerate development of up to 4,000 MW of clean energy resources, 200 MW of firm, dispatchable resources, and up to 300 MW of other dispatchable resources. A recommended portfolio of resources will be filed December 2025 and a decision is expected in February 2026.
Current wording
Near-Term Procurement —In August 2025, PSCo filed a joint motion with state agencies to initiate a “fast-tracked” solution for tax-advantaged new generation resources. The CPUC approved the request in September 2025 with bids submitted in October 2025. The procurement seeks to accelerate development of up to 4,000 nameplate MW of clean energy resources, 200 accredited MW of firm, dispatchable resources, and up to 300 accredited MW of other dispatchable resources.
Previous wording
•Intervenor direct testimony: March 20, 2026
Current wording
•Staff and Intervenor direct testimony: May 1, 2026
Previous wording
SPS Resource Plan (IRP)— In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. SPS’ projected resource needs range from approximately 5,300 MW to 10,200 MW of nameplate capacity by 2030. In February 2024, the NMPRC accepted the IRP.
Current wording
SPS Resource Acquisition— In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources.
Previous wording
In July 2025, the portfolio selection report was publicly filed with the NMPRC with 3,121 MW of accredited capacity resources, including the following:
Current wording
In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited capacity by 2030. In July 2025, the portfolio selection report was publicly filed with the NMPRC with 3,121 MW of accredited capacity resources, including the following:
Previous wording
SPS filed or expects to file Certificate of Convenience and Necessity filings for the specific assets with the PUCT and NMPRC in 2025, with approvals expected in 2026.
Current wording
SPS filed Certificate of Convenience and Necessity filings for the specific assets with the PUCT and NMPRC in 2025, with approvals expected in 2026.
Previous wording
In October 2025, SPS issued a second RFP to solicit 870 MW of accredited capacity (approximately 1,500 MW to 3,000 MW nameplate capacity) through 2032. Additional resources will be evaluated to meet the New Mexico Renewable Portfolio Standard compliance need. Bids are due in January 2026, and the portfolio is expected to be filed in the second half of 2026.
Current wording
In October 2025, SPS issued a RFP to solicit 870 MW of accredited capacity (approximately 1,500 MW to 3,000 MW nameplate capacity) through 2032. Additional resources will be evaluated to meet the New Mexico Renewable Portfolio Standard compliance need. Bids were received in January 2026, and the portfolio is expected to be filed in the second half of 2026.
Previous wording
Excess Liability Insurance Deferral– In March 2025, SPS filed a request with the PUCT and in April 2025, SPS filed a request with the NMPRC for deferred accounting treatment for incremental excess liability insurance expense incurred as a result of the October 2024 policy renewal, estimated at approximately $30 million across the two jurisdictions. In October 2025, the NMPRC approved the request, resulting in a deferral of approximately $15 million of incremental excess liability insurance costs in 2025. A PUCT decision is expected in the first quarter of 2026.
Current wording
Excess Liability Insurance Deferral– In early 2025, SPS filed requests with the NMPRC and PUCT for deferred accounting treatment for incremental excess liability insurance expense incurred as a result of the October 2024 policy renewal, estimated at approximately $30 million across the two jurisdictions. In October 2025, the NMPRC approved the request, resulting in a deferral of approximately $15 million of incremental excess liability insurance costs in 2025 and $3 million in the first quarter of 2026. In January 2026, SPS, PUCT Staff and other intervenors filed a black box settlement expected to result in annual deferrals of approximately $8 million in 2026 and 2027. A PUCT decision is expected in the first half of 2026.
Previous wording
In 2025, several executive orders have been issued imposing new global and country-specific tariffs on many imports, which may impact our procurement and development activities. Additionally, executive orders and actions from government agencies may impact the permitting of wind and solar facilities and the retirement of coal facilities.
Current wording
Executive orders have been issued imposing new global and country-specific tariffs on many imports, which may impact our procurement and development activities. Additionally, executive orders and actions from government agencies may impact the permitting of wind and solar facilities and the retirement of coal facilities.
Previous wording
Throughout 2025, the EPA has announced various regulatory actions addressing a wide range of environmental regulations. Xcel Energy will continue to monitor these proposed rules as they move toward final action. Additionally, any other amendments and changes to rules will be evaluated as proposed by the EPA.
Current wording
Throughout 2025 and 2026, the EPA has announced various regulatory actions addressing a wide range of environmental regulations. Xcel Energy will continue to monitor these proposed rules as they move toward final action. Additionally, any other amendments and changes to rules will be evaluated as proposed by the EPA.
Previous wording
Power Plant Greenhouse Gas Regulations — In April 2024, the EPA published final rules addressing control of CO 2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO 2 control requirements vary by subcategory.
Current wording
Power Plant Greenhouse Gas Regulations — In April 2024, the EPA published final rules addressing control of CO 2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation.
Showing the first 40 of 58 pairs. Open the source sections for the rest.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
The procedural schedule is as follows:
Rearranged previous paragraphs (6)
Previous report — wording carried elsewhere
As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. Gas decoupling mechanisms (and electric sales true-up in 2024) in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.
Previous report — wording carried elsewhere
Xcel Energy 2025 Earnings Guidance— Xcel Energy’s 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a)
Previous report — wording carried elsewhere
•Weather-normalized retail firm natural gas sales are projected to be flat.
Previous report — wording carried elsewhere
Key assumptions as compared with 2025 actual levels unless noted:
Previous report — wording carried elsewhere
•Normal weather patterns for the year.
Previous report — wording carried elsewhere
•Weather-normalized retail electric sales are projected to increase ~3%.