XCEL ENERGY INC
For the period ended Sep 30, 2026. Filed Oct 29, 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.
Sep 30, 2026 · Filed Oct 29, 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 2026-06-30; filed 2026-07-30.
0000072903-26-000154
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-09-30; filed 2026-10-29.
0000072903-26-000181
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 217 previous paragraphs and 245 current paragraphs.
150 unchanged; 53 reworded; 32 added; 13 removed; 1 previous and 10 current paragraphs rearranged.
Tables are not compared: 21 previous and 23 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 (32)
Current report
Marshall Wildfire Litigation— In September 2025, Xcel Energy and other defendants reached settlement agreements in principle that resolved all claims relating to the 2021 Marshall Wildfire. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlements. During the three months ended Sept. 30, 2025, PSCo recognized a non-recurring $287 million charge as a result of the settlement.
Current report
•Residential sales — Increase is due to both customer growth and higher use per customer across jurisdictions.
Current report
Electric fuel and purchased power expenses decreased $31 million for the third quarter of 2026 and $272 million year-to-date. The year-to-date change was primarily due to lower commodity prices, largely in SPS, as well as timing of fuel recovery mechanisms.
Current report
Minnesota Electric Rate Case Stay-Out Petition —On Oct. 9th, 2026, NSP-Minnesota filed an Electric Customer Rate Stability Plan with the MPUC, as an alternative to the planned upcoming rate case filing.
Current report
The terms of the proposed plan are as follows:
Current report
•Customer base rate freeze for calendar years 2027 and 2028.
Current report
•Accelerated recognition of federal Investment Tax Credit benefits related to five battery storage projects over two years. This acceleration will act as an offset to the incremental revenue requirement impact of ongoing necessary capital improvements.
Current report
•Continuation of other true-up and tracker mechanisms as approved in NSP-Minnesota’s most recent Electric Rate Case.
Current report
A MPUC decision on the proposed Rate Stability Plan has been requested by January 2027. If not approved, NSP-Minnesota expects to file an electric rate case in early 2027.
Current report
Final rates will take effect in the first quarter of 2027.
Current report
NSP-Wisconsin
Current report
Proposed Sale of Michigan Operations
Current report
In October 2026, NSP-Wisconsin announced that it has entered into agreements to sell its approximately $150 million of Michigan electric and gas assets to Upper Peninsula Power Company and SEMCO ENERGY Gas Company, respectively, contingent on approvals of the MPSC, PSCW and FERC.
Current report
NSP-Wisconsin and the buyers plan to file requests for regulatory approvals by the end of 2026, with the transactions anticipated to close in 2027. The timing and amount of the gain for the transactions will be dependent on customary closing conditions and resolution of the regulatory approval processes.
Current report
PSCo received a final decision from the CPUC in September 2026. Terms of the final decision include:
Current report
The CPUC approved the settlement agreement with minor modifications. Rates were implemented in October 2026.
Current report
SPS 2026 IRP —In October 2026, SPS filed its 2026 IRP with the NMPRC, which demonstrates projected load growth and shows energy and capacity resource portfolio needs under three different load forecast scenarios. Based on these forecast scenarios and the progress of existing resource acquisition processes, SPS' initial IRP modeling identified resource needs of approximately 2,000 MW of incremental accredited capacity by 2034. Following NMPRC action on the IRP, SPS expects to issue a competitive all-source solicitation for new generation in mid-2027 with project selection expected in early 2028.
Current report
SPS — In the third quarter of 2026, SPS filed proposed tariff modifications in Texas to address new and certain existing loads over 75 MW. The proposed tariff includes a minimum initial term of 15 years, minimum bill provisions, termination and exit fees, and credit requirements. SPS expects to propose an incremental cost test applicable to this tariff in its next rate case.
Current report
SPS expects to file similar tariff modifications in New Mexico in the fourth quarter of 2026.
Current report
Capital Expenditures —Base capital expenditures for Xcel Energy for 2027 through 2031:
Current report
(a)Other category includes intercompany transfers for equipment with long lead times.
Current report
The plan does not include any potential incremental generation from the current generation RFPs across jurisdictions, investments to serve future large load customers or additional transmission investment that may come from future planning processes including MISO and SPP.
Current report
Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.
Current report
Financing for Capital Expenditures through 2031— Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Current estimated financing plans of Xcel Energy for 2027-2031 (includes the impact of tax credit transferability):
Current report
(a)Net of dividends and pension funding.
Current report
(b)Reflects a combination of short and long-term debt; net of refinancing.
Current report
(c)Amount could include other financing instruments that receive equity credit from the credit rating agencies.
Current report
(a)2024 10 year financing re-opened in 2026. Bonds are due in 2034.
Current report
In the third quarter of 2026, 10.5 million shares were issued (net proceeds of $819 million) in settlements of forward sale agreements or in ATM cash transactions.
Current report
•Capital rider revenue is projected to increase $370 million to $380 million. The decrease from prior guidance is primarily offset by depreciation and AFUDC impacts.
Current report
•AFUDC - equity is projected to increase $180 million to $190 million. The increase from prior guidance is primarily offset by lower revenue.
Current report
•Depreciation expense is projected to increase approximately $460 million to $470 million.
Removed paragraphs (13)
Previous report
(a)Decrease primarily due to recognition of interim rate refunds in the Minnesota Electric Rate Case. Reduced electric revenue was more than offset by corresponding reductions in depreciation expense due to nuclear life extensions approved in the case.
Previous report
A final written MPUC order is expected by July 31, 2026.
Previous report
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%.
Previous report
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. In July 2026, the MPUC declined to modify the treatment of prepaid pension asset.
Previous report
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.
Previous report
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. In May 2026, the SDPUC approved the settlement agreement, and rates became effective July 1, 2026.
Previous report
•Transfer of the previous Transmission Cost Adjustment investments into rate base.
Previous report
A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.
Previous report
Hearings to discuss the settlement took place in July 2026. A CPUC decision and implementation of final rates is anticipated in the fourth quarter of 2026.
Previous report
The following resources are included in SPS’ preferred portfolio:
Previous report
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 $7 million in the six months ended June 30, 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 forthcoming.
Previous report
Similar large load tariff requests are expected to be filed in New Mexico and Texas by the end of 2026.
Previous report
In June 2025, the EPA proposed to repeal these and all other GHG emissions standards for the power sector. In the alternative, the EPA proposed to repeal a narrower subset of the 2024 regulations.
Reworded paragraphs (53)
Previous wording
The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Current wording
The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer.
Previous wording
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. The MPUC ordered the ALJ-recommended disallowance in May 2026. Total non-recurring charges of $38 million were recorded to electric revenues during the six months ended June 30, 2026 for incremental customer refunds, including interest.
Current wording
Prairie Island Outage Refunds — In a September 2024 decision, the MPUC ruled that NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in an extended 2023-2024 outage. In May 2026, the MPUC ordered a disallowance of $41 million for estimated replacement power costs incurred during the outage. Total non-recurring charges of $38 million were recorded to electric revenues during the nine months ended Sept. 30, 2026 for incremental customer refunds, including interest.
Previous wording
Marshall Wildfire Litigation— In the six months ended June 30, 2026, PSCo recognized $19 million of net reductions to operating expenses due primarily to an increase in the estimated amount recoverable from insurance for non-recurring Marshall Wildfire costs.
Current wording
During the nine months ended Sept. 30, 2026, PSCo recognized $18 million of net reductions to operating expenses due primarily to an increase in the estimated amount recoverable from insurance for non-recurring Marshall Wildfire costs.
Previous wording
Xcel Energy’s second quarter diluted GAAP and ongoing earnings were $0.93 per share compared with $0.75 per share in the same period in 2025. The change in earnings per share was primarily driven by increased recovery of electric infrastructure investments, partially offset by higher financing costs. 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 third quarter diluted GAAP and ongoing earnings were $1.52 per share in 2026, compared with GAAP earnings of $0.88 per share and ongoing earnings of $1.24 in the same period in 2025. The change in ongoing earnings per share was primarily driven by increased recovery of electric infrastructure investments, earnings on equity method investments and unseasonably warm weather, partially offset by higher financing costs. 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 and ongoing earnings increased $0.06 per share for the second quarter of 2026. Year-to-date GAAP earnings increased $0.03 per share and ongoing earnings increased $0.01 per share. The increase in year-to-date ongoing earnings was driven by higher recovery of electric infrastructure investments which was partially offset by unfavorable weather. The difference between GAAP and ongoing earnings was driven by an increase in the estimated amount recoverable from insurance for Marshall Wildfire costs.
Current wording
PSCo— GAAP earnings increased $0.49 per share and ongoing earnings increased $0.13 per share for the third quarter of 2026. Year-to-date GAAP earnings increased $0.52 per share and ongoing earnings increased $0.14 per share. The increase in year-to-date ongoing earnings was driven by higher recovery of electric infrastructure investments and increased AFUDC, which was partially offset by increased interest charges and depreciation expenses. The difference between GAAP and ongoing earnings was driven by the impact of Marshall Wildfire litigation.
Previous wording
NSP-Minnesota— GAAP and ongoing earnings increased $0.05 per share for the second quarter of 2026. Year-to-date GAAP earnings increased $0.03 per share and ongoing earnings increased $0.07 per share. 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 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.
Current wording
NSP-Minnesota— GAAP and ongoing earnings decreased $0.02 per share for the third quarter of 2026. Year-to-date GAAP earnings increased $0.01 per share and ongoing earnings increased $0.05 per share. 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 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
SPS— GAAP and ongoing earnings increased $0.02 per share for the second quarter and $0.06 per share year-to-date. The year-to-date change was driven by sales growth and higher recovery of electric infrastructure investments, partially offset by increased depreciation expense.
Current wording
SPS— GAAP and ongoing earnings increased $0.07 per share for the third quarter and $0.12 per share year-to-date. The year-to-date change was driven by sales growth, weather, and higher recovery of electric infrastructure investments, partially offset by increased depreciation expense and interest charges.
Previous wording
NSP-Wisconsin— GAAP and ongoing earnings increased $0.01 per share for the second quarter and $0.05 year-to-date. The year-to-date change was driven by higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation expense and interest charges.
Current wording
NSP-Wisconsin— GAAP and ongoing earnings increased $0.01 per share for the third quarter and $0.06 year-to-date. The year-to-date change was driven by higher recovery of electric and natural gas infrastructure investments, partially offset by increased O&M expenses, depreciation expense and interest charges.
Previous wording
•C&I sales — Increase is due to higher use per customer in SPS (6.0%) and NSP-Minnesota (2.0%) and customer growth in NSP-Wisconsin (1.0%). Increased activity in the energy sector in SPS and the manufacturing sector in all jurisdictions contributed to the sales growth.
Current wording
•C&I sales — Increase is due to higher use per customer in SPS (5.6%) and NSP-Minnesota (2.8%) and customer growth in NSP-Wisconsin (0.9%). Increased activity in the energy sector in SPS and the manufacturing sector in all jurisdictions contributed to the sales growth.
Previous wording
•Decrease in natural gas sales was driven primarily by reduced use per customer in most jurisdictions and customer classes.
Current wording
•Decrease in natural gas sales was driven primarily by reduced use per customer in most jurisdictions and customer classes, partially offset by customer growth in all jurisdictions.
Previous 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 $240 million for the second quarter of 2026 and $241 million year-to-date. The year-to-date change was primarily due to lower commodity prices, largely in SPS..
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.
Previous wording
Natural gas sold and transported decreased $41 million for the second quarter of 2026 and $34 million year-to-date. The year-to-date change was primarily due to decreased volumes in PSCo, partially offset by higher commodity prices.
Current wording
Natural gas sold and transported decreased $3 million for the third quarter of 2026 and $37 million year-to-date. The year-to-date change was primarily due to decreased volumes in PSCo, partially offset by higher commodity prices.
Previous wording
O&M Expenses — O&M expenses increased $16 million for the second quarter of 2026 and $5 million year-to-date. The year-to-date change was primarily due to increased generation costs.
Current wording
O&M Expenses — O&M expenses increased $67 million for the third quarter of 2026 and $72 million year-to-date. The year-to-date change was primarily due to increased generation, wildfire mitigation and gas system costs.
Previous wording
Depreciation and Amortization— Depreciation and amortization decreased $60 million for the second quarter of 2026 and $20 million year-to-date. The year-to-date change was primarily due to the recognition of 2025 and 2026 depreciation reductions (nuclear life extensions) in the second quarter of 2026, partially offset by system expansion.
Current wording
Depreciation and Amortization— Depreciation and amortization increased $41 million for the third quarter of 2026 and $21 million year-to-date. The year-to-date change was primarily due to system expansion, partially offset by the recognition of 2025 and 2026 depreciation reductions (nuclear life extensions) in the second quarter of 2026.
Previous wording
Interest Charges— Interest charges increased $94 million for the second quarter of 2026 and $174 million year-to-date. The year-to-date change was primarily due to higher debt levels.
Current wording
Interest Charges— Interest charges increased $100 million for the third quarter of 2026 and $274 million year-to-date. The year-to-date change was primarily due to higher debt levels.
Previous wording
Earnings from Equity Method Investments— Earnings from equity method investments increased $84 million for the second quarter of 2026 and $98 million year-to-date. The year-to-date change was primarily due to unrealized gains on investment funds’ interests in energy technology companies in the first six months of 2026 and losses in the first six months of 2025.
Current wording
Earnings from Equity Method Investments— Earnings from equity method investments increased $71 million for the third quarter of 2026 and $169 million year-to-date. The year-to-date change was primarily due to unrealized gains on investment funds’ interests in energy technology companies.
Previous wording
AFUDC, Equity and Debt— AFUDC increased $54 million for the second quarter of 2026 and $115 million year-to-date. The year-to-date change was primarily due to system investment.
Current wording
AFUDC, Equity and Debt— AFUDC increased $68 million for the third quarter of 2026 and $183 million year-to-date. The year-to-date change was primarily due to system investment.
Previous wording
In June 2026, the MPUC issued a verbal decision. Terms of the decision include:
Current wording
In July 2026, the MPUC issued a written order. Terms of the order include:
Previous wording
•Estimated rate increase of approximately $211 million over two years (annual average increase of 2.9%).
Current wording
•Rate increase of approximately $211 million over two years (annual average increase of 2.9%).
Previous wording
•ROE of 9.60%, an increase from the current 9.25% ROE, while maintaining the equity ratio of 52.5%.
Current wording
•ROE of 9.60% and equity ratio of 52.5%.
Previous wording
An ALJ report is expected by September 2026 and a MPUC decision is expected in November 2026.
Current wording
In August 2026, the ALJ issued their report. A MPUC decision is expected in the fourth quarter of 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. NSP-Minnesota filed for approval of recommended projects in March 2026. A decision is expected in the third quarter of 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, which were approved by the MPUC in September 2026.
Previous 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.
Current wording
•NSP-Minnesota and NSP-Wisconsin may continue to file additional RFPs throughout 2026 and 2027 for resource needs as part of their Upper Midwest resource planning efforts.
Previous wording
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 contract, 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. A decision is expected in early 2027.
Current wording
Large Load Agreement — Pine Island Data Center —In the first quarter of 2026, NSP-Minnesota entered into an ESA 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 contract, 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 ESA, including a proposed Clean Energy Accelerator Charge for 1,900 MW of clean energy resources, was filed with the MPUC in April 2026. A decision is expected in early 2027.
Previous wording
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 wording
Approvals for 1,000 MW of resources for the Clean Energy Accelerator program have been received as part of existing resource acquisition processes. The remaining resources are expected to be requested in those processes by the second quarter of 2027.
Previous wording
In June 2026, PSCo, CPUC Staff and various other parties filed a comprehensive non-unanimous settlement agreement. The AARP, City of Boulder and the UCA oppose the settlement. Other parties either support portions of the settlement or do not oppose it. Terms of the settlement include:
Current wording
In June 2026, PSCo, CPUC Staff and various other parties filed a comprehensive non-unanimous settlement agreement. The AARP, City of Boulder and the UCA opposed the settlement. Other parties either supported portions of the settlement or did not oppose it.
Previous wording
•Revenue increase (excluding rider roll-ins) of $225 million (6.3% total, or an annual average of 2.05% since the last rate case), based on a 2025 historic test year using year-end rate base with limited forward looking known and measurable adjustments.
Current wording
•Revenue increase (excluding rider roll-ins) of $184 million (5.2% total, or an annual average of 1.7% since the last rate case), based on a 2025 historical test year using a 13-month average.
Previous wording
•A performance framework applicable to the operation of Comanche Unit 3 coal facility from effective date of rates through 2029.
Current wording
•A performance framework applicable to the operation of Comanche Unit 3 coal facility from effective date of rates through 2029. PSCo also agreed to file a prudence review related to the outage at the unit (from August 2025 to September 2026) in June 2027.
Previous wording
•Revenue increase of $123 million (7.5% total, or an annual average of 3.7% since the last rate case), based on a 2025 historic test year using average rate base with forward looking known and measurable adjustments.
Current wording
•Revenue increase of $123 million (7.5% total, or an annual average of 3.7% since the last rate case), based on a 2025 historic test year using a 13-month average rate base with forward looking known and measurable adjustments.
Previous 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 3% compound annual sales growth through 2031 and a generation capacity need of approximately 5,400 MW.
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 revised load forecast methodology and authorized the Company to initiate its request for proposals. PSCo filed a request for reconsideration of various aspects of the decision which were approved in February 2026.
Previous wording
PSCo filed a request for reconsideration of various aspects of the decision which were approved in February 2026. The RFP for the Phase II competitive solicitation process is 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 3,800 MW of approved acquisitions from the Near-Term Procurement RFP).
Current wording
The RFP for the Phase II competitive solicitation process was issued in the third quarter of 2026. This RFP is specifically seeking to acquire 500 MW of additional capacity by 2031 with potential upside for additional capacity as new large load customers are approved (after consideration of 3,800 MW of approved acquisitions from the Near-Term Procurement RFP). Bids are due in December 2026, and a CPUC decision is expected in the second half of 2027.
Previous wording
A hearing on the non-unanimous stipulation took place in July 2026. An NMPRC decision is anticipated in the fourth quarter of 2026, with implementation of rates expected in December 2026.
Current wording
A hearing on the non-unanimous stipulation took place in July 2026. On Oct. 23, 2026, SPS received the Hearing Examiners’ Report, which recommended NMPRC approval with certain minor modifications. Any exceptions are required to be filed by Nov. 2, 2026. An NMPRC decision is anticipated in the fourth quarter of 2026, with implementation of rates expected in December 2026.
Previous 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.
Current wording
SPS 2023 Integrated Resource Plan— 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 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. SPS has received NMPRC approval of the CCN filings for the specific assets, and PUCT approval is expected in the third quarter. SPS is continuing to pursue approximately 2,800 MW of accredited resources, including approximately 4,000 MW of nameplate capacity company owned resources and approximately 500 MW of nameplate capacity PPAs.
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. SPS filed for approval of approximately 2,800 MW of accredited resources, including approximately 4,000 MW of nameplate capacity company owned resources and approximately 500 MW of nameplate capacity PPAs. SPS has received NMPRC approval of the CCN filings for the assets. In October 2026, the PUCT approved the self build portfolio with the exception of the Plant X battery storage project. The approval includes performance and cost cap guarantees. SPS will be seeking rehearing on this decision.
Previous wording
In October 2025, SPS issued a RFP to solicit 870 MW of accredited capacity through 2032 (approximately 1,500 MW to 3,000 MW nameplate capacity, or more depending on resource mix), with additional resources to be evaluated to meet the New Mexico RPS compliance need. Bids were received in January 2026, and the portfolio selection report was publicly filed with the NMPRC in July 2026. Project CCNs are expected to be filed in late 2026 or early 2027.
Current wording
In October 2025, SPS issued a RFP to solicit 870 MW of accredited capacity through 2032 (approximately 1,500 MW to 3,000 MW nameplate capacity, or more depending on resource mix), with additional resources to be evaluated to meet the New Mexico RPS compliance need. The portfolio selection report was publicly filed with the NMPRC in July 2026, with a preferred portfolio that contains approximately 2,600 MW of nameplate capacity company owned resources and approximately 1,300 MW of nameplate capacity PPAs. Project CCNs are expected to be filed in early 2027.
Previous wording
NSP-Wisconsin — NSP-Wisconsin filed a proposed tariff in the second quarter of 2026, which would be mandatory for new loads over 100 MW and requires the customer pay for generation and other infrastructure costs needed to serve the load, if approved as filed. The proposed tariff also includes a minimum initial term of 15 years, minimum bill provisions, termination and exit fees, and credit requirements. A PSCW decision is expected in early 2027.
Current wording
NSP-Wisconsin — NSP-Wisconsin filed a proposed tariff in the second quarter of 2026, which would be mandatory for new loads over 100 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 PSCW decision is expected in early 2027.
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.
Current wording
Power Plant Greenhouse Gas Regulations — In April 2024, the EPA published final rules addressing greenhouse gas emissions from the power sector. The rules establish requirements for new natural gas-fired generating units and emission guidelines for existing coal and certain natural gas generation. In September 2026, the EPA issued a final rule repealing portions of the 2024 rules, including carbon capture and storage (CCS) standards. The EPA simultaneously proposed to rescind the remaining power plant GHG regulations.
Previous wording
Endangerment Finding— In February 2026, the EPA issued a final rule repealing the 2009 Endangerment Finding and associated regulations addressing GHG emissions from new motor vehicles and engines under the Clean Air Act. Xcel Energy will monitor any additional proposed rules and evaluate the impacts of any final rule on the utility sector.
Current wording
Endangerment Finding— In February 2026, the EPA issued a final rule repealing the 2009 Endangerment Finding and associated regulations addressing GHG emissions from new motor vehicles and engines under the Clean Air Act. Xcel Energy will monitor any additional actions and evaluate the impacts.
Previous wording
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the six months ended June 30:
Current wording
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the nine months ended Sept. 30:
Previous wording
A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations by approximately $2 million and $3 million at June 30, 2026 and June 30, 2025.
Current wording
A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations by an immaterial amount and approximately $2 million at Sept. 30, 2026 and Sept. 30, 2025, respectively.
Showing the first 40 of 53 pairs. Open the source sections for the rest.
Rearranged current paragraphs (10)
Current report — wording carried from elsewhere
(a)Amounts may not add due to rounding.
Current report — wording carried from elsewhere
Xcel Energy 2026 Earnings Guidance —Xcel Energy’s 2026 ongoing earnings guidance is a narrowed range of $4.10 to $4.16 per share, from the original guidance of $4.04 to $4.16 per share.(a)
Current report — wording carried from elsewhere
•Weather-normalized retail firm natural gas sales are projected to be flat.
Current report — wording carried from elsewhere
Key assumptions as compared with 2026 actual levels unless noted:
Current report — wording carried from elsewhere
•Constructive outcomes in all pending rate case and regulatory proceedings.
Current report — wording carried from elsewhere
•Normal weather patterns for the year.
Current report — wording carried from elsewhere
•Weather-normalized retail electric sales are projected to increase ~5%.
Current report — wording carried from elsewhere
•O&M expenses are projected to increase ~4%.
Current report — wording carried from elsewhere
•Property taxes are projected to increase $30 million to $40 million.
Current report — wording carried from elsewhere
•Interest expense (net of AFUDC - debt) is projected to increase $320 million to $330 million, net of interest income.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Based on current estimates and assumptions, Xcel Energy has determined that due to scheduled plant retirements, there is minimal financial or operational impact associated with these requirements and believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.