Xcel Energy Inc.

10/29/2026 | Press release | Distributed by Public on 10/29/2026 13:31

Quarterly Report for Quarter Ending Sept. 30, 2026 (Form 10-Q)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy's financial condition, results of operations and cash flows during the periods presented or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements. Due to the seasonality of Xcel Energy's operating results, quarterly financial results are not an appropriate base from which to project annual results.
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.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company's financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP.
Xcel Energy's management uses non-GAAP measures for financial planning and analysis, for reporting results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors' understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies' similarly titled non-GAAP financial measures.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.'s diluted EPS is calculated using the treasury stock method.
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy's core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted EPS, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP.
The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2026 2025 2026 2025
GAAP net income $ 960 $ 524 $ 2,102 $ 1,451
Prairie Island outage refunds - - 38 -
Marshall Wildfire litigation 1 287 (18) 287
Tax effect - (74) (5) (74)
Ongoing earnings $ 961 $ 737 $ 2,117 $ 1,664
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.
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.
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.
Results of Operations
The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. Diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole.
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).
Summarized diluted EPS for Xcel Energy:
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share 2026 2025 2026 2025
PSCo $ 0.57 $ 0.08 $ 1.31 $ 0.79
NSP-Minnesota 0.51 0.53 1.18 1.17
SPS 0.34 0.27 0.67 0.55
NSP-Wisconsin 0.08 0.07 0.25 0.19
Earnings from equity method investments - WYCO 0.01 0.01 0.03 0.02
Regulated utility (a)
1.52 0.96 3.44 2.72
Xcel Energy Inc. and Other - (0.07) (0.10) (0.24)
GAAP diluted EPS (a)
$ 1.52 $ 0.88 $ 3.34 $ 2.47
Prairie Island outage refunds - - 0.04 -
Marshall Wildfire litigation - 0.36 (0.02) 0.36
Ongoing diluted EPS (a)
$ 1.52 $ 1.24 $ 3.37 $ 2.84
(a)Amounts may not add due to rounding.
Summary of Earnings
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.
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.
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.
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.
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 increase in earnings was largely due to unrealized gains on the investment funds' interests in energy technology companies, partially offset by higher debt levels.
Changes in GAAP and Ongoing EPS
Components significantly contributing to changes in 2026 EPS compared to 2025:
Diluted Earnings (Loss) Per Share Three Months Ended Sept. 30 Nine Months Ended Sept. 30
GAAP EPS - 2025 $ 0.88 $ 2.47
Components of change - 2026 vs. 2025
Marshall Wildfire litigation 0.36 0.38
Lower electric fuel and purchased power 0.04 0.35
Higher electric revenues 0.32 0.32
Higher AFUDC equity and debt 0.11 0.29
Higher earnings from equity method investments 0.09 0.21
Higher interest charges (0.13) (0.35)
Common equity financing (0.10) (0.24)
Higher O&M expenses (0.08) (0.09)
Other, net 0.03 -
GAAP EPS - 2026 $ 1.52 $ 3.34
Prairie Island outage refunds - 0.04
Marshall Wildfire litigation - (0.02)
Ongoing EPS - 2026 (a)
$ 1.52 $ 3.37
(a)Amounts may not add due to rounding.
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings -Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy's financial performance. However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.
Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather. Typically, sales are not impacted in the first or fourth quarter due to THI or CDD.
Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage increase (decrease) in normal and actual HDD, CDD and THI:
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2026 vs. Normal 2025 vs. Normal 2026 vs. 2025 2026 vs. Normal 2025 vs. Normal 2026 vs. 2025
HDD (47.2) % (30.6) % (23.9) % (15.4) % (1.9) % (13.8) %
CDD 30.0 (7.2) 40.6 28.0 (6.8) 38.6
THI 30.5 12.3 16.8 22.5 7.3 14.2
Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2026 vs. Normal 2025 vs. Normal 2026 vs. 2025 2026 vs. Normal 2025 vs. Normal 2026 vs. 2025
Retail electric $ 0.144 $ 0.006 $ 0.138 $ 0.116 $ (0.001) $ 0.117
Sales true-up
(0.072) - (0.072) (0.065) - (0.065)
Electric total $ 0.072 $ 0.006 $ 0.066 $ 0.051 $ (0.001) $ 0.052
Firm natural gas (0.002) - (0.002) (0.089) - (0.089)
Decoupling - 0.001 (0.001) 0.010 0.003 0.007
Natural gas total $ (0.002) $ 0.001 $ (0.003) $ (0.079) $ 0.003 $ (0.082)
Total $ 0.070 $ 0.007 $ 0.063 $ (0.028) $ 0.002 $ (0.030)
Sales - Sales growth (decline) for actual and weather-normalized sales volumes in 2026 compared to 2025:
Three Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual
Electric residential 13.6 % 6.9 % 22.9 % 8.0 % 11.7 %
Electric C&I 3.5 6.4 6.7 1.6 5.4
Total retail electric sales 7.1 6.5 9.5 3.5 7.3
Firm natural gas sales (4.2) (2.1) N/A (7.0) (3.8)
Three Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized
Electric residential 4.4 % 1.0 % 6.7 % 1.3 % 3.2 %
Electric C&I (0.9) 4.7 5.2 (0.4) 2.9
Total retail electric sales 1.0 3.4 5.6 0.2 3.0
Firm natural gas sales (1.5) (2.7) N/A (7.0) (2.2)
Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual
Electric residential 3.4 % 3.3 % 6.0 % 2.5 % 3.7 %
Electric C&I 0.8 3.8 6.6 1.5 3.7
Total retail electric sales 1.6 3.6 6.6 1.8 3.7
Firm natural gas sales (19.9) (3.3) N/A (5.2) (13.6)
Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized
Electric residential 1.7 % 1.1 % 0.7 % 1.6 % 1.3 %
Electric C&I (0.3) 3.3 5.9 1.1 3.0
Total retail electric sales 0.3 2.5 5.1 1.2 2.5
Firm natural gas sales (2.4) 0.1 N/A (2.3) (1.6)
Weather-normalized electric sales growth (decline) - year-to-date
•Residential sales - Increase is due to both customer growth and higher use per customer across jurisdictions.
•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.
Weather-normalized natural gas sales growth (decline) - year-to-date
•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.
Electric Revenues
Electric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.
(Millions of Dollars) Three Months Ended Sept. 30, 2026 vs. 2025 Nine Months Ended Sept. 30, 2026 vs. 2025
Non-fuel riders $ 93 $ 296
Sales and demand 42 111
Conservation and demand side management (offset in expense) 29 70
Wholesale transmission 25 69
Regulatory rate outcomes (CO, MN, ND, SD and WI) 88 68
Estimated impact of weather (net of sales true-up) 50 39
Recovery of higher (lower) cost of electric fuel and purchased power 11 (158)
PTCs flowed back to customers (offset by ETR) (55) (114)
Wholesale generation (41) (85)
Prairie Island outage refunds - (38)
Other, net 8 (5)
Total increase $ 250 $ 253
Natural Gas Revenues
Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.
(Millions of Dollars) Three Months Ended Sept. 30, 2026 vs. 2025 Nine Months Ended Sept. 30, 2026 vs. 2025
Estimated impact of weather (net of decoupling) $ (1) $ (63)
Recovery of lower cost of natural gas (7) (42)
Regulatory rate outcomes (MN and WI) 7 44
Other, net 9 13
Total increase (decrease) $ 8 $ (48)
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 $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.
Cost of Natural Gas Sold and Transported - Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
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.
Non-Fuel Operating Expenses and Other Items
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.
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.
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.
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.
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.
Public Utility Regulation and Other
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and demand side management efforts and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations.
Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy's Annual Report on Form 10-K for the year ended Dec. 31, 2025 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings
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.
The terms of the proposed plan are as follows:
•Customer base rate freeze for calendar years 2027 and 2028.
•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.
•Continuation of other true-up and tracker mechanisms as approved in NSP-Minnesota's most recent Electric Rate Case.
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.
2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota 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. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million.
In July 2026, the MPUC issued a written order. Terms of the order include:
•Rate increase of approximately $211 million over two years (annual average increase of 2.9%).
•ROE of 9.60% and equity ratio of 52.5%.
•Continuation of existing true-up mechanisms inclusive of the sales true-up, coupled with authorization of new tracker mechanisms.
Final rates will take effect in the first quarter of 2027.
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.
In May 2026, NSP-Minnesota and certain intervenors reached a non-unanimous settlement, based on a total revenue increase of $38 million (4.9%) and a weighted average cost of capital of 7.21% (an increase from the previously authorized 7.16%).
In August 2026, the ALJ issued their report. A MPUC decision is expected in the fourth quarter of 2026.
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. The procedural schedule is yet to be determined.
NSP-Wisconsin
Proposed Sale of Michigan Operations
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.
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.
NSP System
Pending and Recently Concluded Regulatory Proceedings
NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.
•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.
•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. Short-listed projects were announced in June 2026, and filing for requisite regulatory approval is expected by the end of 2026.
•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.
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.
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.
PSCo
Pending and Recently Concluded Regulatory Proceedings
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.
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.
PSCo received a final decision from the CPUC in September 2026. Terms of the final decision include:
•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.
•ROE of 9.3% and equity ratio of 54.5%.
•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.
•Continuation of previously authorized trackers and deferrals.
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.
In July 2026, PSCo, CPUC Staff, the UCA, the Colorado Energy Office, Western Resource Advocates/Sierra Club, Energy Outreach Colorado and various other parties filed a comprehensive non-unanimous settlement agreement. Several parties either do not oppose or take no position on the settlement, and one transportation shipper opposes it. Key terms of the settlement include:
•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.
•ROE of 9.2% and equity ratio of 54.5%.
The CPUC approved the settlement agreement with minor modifications. Rates were implemented in October 2026.
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.
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.
SPS
Pending and Recently Concluded Regulatory Proceedings
2025 New Mexico Electric Rate Case - In November 2025, SPS filed an electric rate case with the NMPRC. As updated in March 2026, SPS requested a revenue increase of $168 million (16.0%). The request was 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.
In June 2026, SPS, New Mexico Department of Justice, New Mexico Large Customer Group and various other parties filed a comprehensive non-unanimous stipulation. NMPRC Staff opposes certain components of the stipulation.
Terms of the stipulation include:
•Base rate revenue increase of $90 million (7.7% total, or an annual average of 2.4% since the last rate case), based on the filed future test year.
•ROE of 9.5%.
•Equity ratio of 54.70%.
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.
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.
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.
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.
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.
Other
Tariffs, Trade Complaints and Federal Actions
Several trade cases related to anti-dumping and countervailing duty investigations are ongoing and we continue to monitor the potential impacts of these cases.
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.
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.
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.
Large Load/Data Center Tariffs
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.
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.
NSP-Minnesota -The tariff, which was approved by the MPUC in June 2026, is 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.
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.
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.
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.
SPS expects to file similar tariff modifications in New Mexico in the fourth quarter of 2026.
Critical Accounting Policies and Estimates
Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. The financial and operating environment also may have a significant effect on the operation of the business and results reported. Items considered critical are included within the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2025.
Environmental Regulation
Throughout 2025 and 2026, the EPA has announced various regulatory actions addressing a wide range of environmental regulations. Xcel Energy will continue to monitor proposed rules as they move toward final action. Additionally, any other amendments and changes to rules will be evaluated as proposed by the EPA.
Clean Air Act
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.
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.
Emerging Contaminants of Concern
PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS, but because PFAS are so ubiquitous in products and the environment, it may impact our operations.
In June 2024, the EPA finalized a rule that designated certain PFAS as hazardous substances under CERCLA. In July 2024, the EPA finalized another rule that set enforceable drinking water standards for certain PFAS.
Potential costs for these rules and any additional proposed regulations related to PFAS are uncertain and will be determined on a site specific basis where applicable. If costs are incurred, Xcel Energy believes the costs would be recoverable through rates based on prior state commission practices.
Effluent Limitation Guidelines
In April 2024, the EPA published final rules under the Clean Water Act, setting Effluent Limitations Guidelines and Standards for steam generating coal plants. This rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Based on current estimates and assumptions, Xcel Energy has determined that there is minimal financial or operational impact associated with these requirements and that any costs would be recoverable through rates based on prior state commission practices.
Derivatives, Risk Management and Market Risk
We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.
Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.
Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.
Fair value of net commodity trading contracts as of Sept. 30, 2026:
Futures / Forwards Maturity
(Millions of Dollars) Less Than 1 Year 1 to 3 Years 4 to 5 Years Greater Than 5 Years Total Fair Value
NSP-Minnesota (a)
$ (7) $ (14) $ (1) $ - $ (22)
NSP-Minnesota (b)
(3) (14) (3) (1) (21)
PSCo (a)
(1) - - - (1)
PSCo (b)
- - - - -
$ (11) $ (28) $ (4) $ (1) $ (44)
Options Maturity
(Millions of Dollars) Less Than 1 Year 1 to 3 Years 4 to 5 Years Greater Than 5 Years Total Fair Value
NSP-Minnesota (b)
$ - $ 24 $ 4 $ - $ 28
$ - $ 24 $ 4 $ - $ 28
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the nine months ended Sept. 30:
(Millions of Dollars) 2026 2025
Fair value of commodity trading net contracts outstanding at Jan. 1 $ (15) $ (2)
Contracts realized or settled during the period 3 (1)
Commodity trading contract additions and changes during the period (4) (9)
Fair value of commodity trading net contracts outstanding at Sept. 30 $ (16) $ (12)
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.
The utility subsidiaries' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
(Millions of Dollars) Three Months Ended Sept. 30 Average High Low
2026 $ - $ - $ - $ -
2025 - - 1 -
Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.
A 100-basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $31 million and $13 million at Sept. 30, 2026 and 2025, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants.
Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory liability for nuclear decommissioning costs.
The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.
Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.
Xcel Energy's subsidiaries are subject to credit risk from contracts with generating equipment manufacturers and other suppliers that require deposits or milestone payments. In the event of non-performance by these counterparties, the Xcel Energy subsidiaries could experience credit losses, increased costs or project delays. Xcel Energy frequently seeks to mitigate this risk by requiring parent guarantees, letters of credit or other types of credit support.
Xcel Energy is also subject to credit risk for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.
At Sept. 30, 2026, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $25 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $16 million. At Sept. 30, 2025, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $33 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $32 million.
Fair Value Measurements
Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Note 8 to the consolidated financial statements for further information.
Liquidity and Capital Resources
Cash Flows
Operating Cash Flows
(Millions of Dollars) Nine Months Ended Sept. 30
Cash provided by operating activities - 2025 $ 3,874
Components of change - 2026 vs. 2025
Higher net income 651
Non-cash transactions (206)
Changes in deferred income taxes 7
Changes in working capital 454
Changes in net regulatory and other assets and liabilities 88
Cash provided by operating activities - 2026 $ 4,868
Net cash provided by operating activities increased $994 million for the nine months ended Sept. 30, 2026 compared with the prior year. The increase was largely due to higher net income and insurance reimbursements for the Marshall Wildfire and Smokehouse Creek Fire Complex settlement activity.
Investing Cash Flows
(Millions of Dollars) Nine Months Ended Sept. 30
Cash used in investing activities - 2025 $ (7,492)
Components of change - 2026 vs. 2025
Increased capital expenditures (1,785)
Other investing activities 50
Cash used in investing activities - 2026 $ (9,227)
Net cash used in investing activities increased $1,735 million for the nine months ended Sept. 30, 2026 compared with the prior year. The increase in capital expenditures was largely due to continued system investment in renewable and transmission projects.
Financing Cash Flows
(Millions of Dollars) Nine Months Ended Sept. 30
Cash provided by financing activities - 2025 $ 4,491
Components of change - 2026 vs. 2025
Higher net short-term debt proceeds 875
Higher long-term debt issuances, net of repayments 1,607
Lower proceeds from issuance of common stock (312)
Other financing activities (93)
Cash provided by financing activities - 2026 $ 6,568
Net cash provided by financing activities increased $2,077 million for the nine months ended Sept. 30, 2026 compared with the prior year. The increase was largely related to additional debt to fund capital investment, partially offset by decreased issuances of common stock.
Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.
Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.
•In January 2026, contributions of $75 million were made to Xcel Energy's pension plans.
•In 2025, contributions of $125 million were made to Xcel Energy's pension plans.
•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.
Capital Sources
Short-Term Funding Sources - Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.
Credit Facilities - As of October 28, 2026, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available Cash Liquidity
Xcel Energy Inc. $ 2,000 $ 1,290 $ 710 $ 41 $ 751
PSCo 1,200 48 1,152 659 1,811
NSP-Minnesota 800 44 756 237 993
SPS 600 - 600 637 1,237
NSP-Wisconsin 150 - 150 75 225
Total $ 4,750 $ 1,382 $ 3,368 $ 1,649 $ 5,017
(a)Credit facilities expire in December 2029.
(b)Includes outstanding commercial paper and letters of credit.
Term Loan Agreement - In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and as of October 28, 2026 had borrowed $1.5 billion under the term loan facility.
Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. As of Sept. 30, 2026, the authorized levels for these commercial paper programs are:
•$2 billion for Xcel Energy Inc.
•$1.2 billion for PSCo.
•$800 million for NSP-Minnesota.
•$600 million for SPS.
•$150 million for NSP-Wisconsin.
Money Pool - Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries.
Xcel Energy may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy. The money pool balances are eliminated in consolidation. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.
Capital Expenditures - Base capital expenditures for Xcel Energy for 2027 through 2031:
Base Capital Forecast (Millions of Dollars)
By Regulated Utility 2027 2028 2029 2030 2031 Total
SPS $ 6,720 $ 6,390 $ 7,000 $ 2,890 $ 2,820 $ 25,820
NSP-Minnesota 4,660 4,860 6,010 4,920 4,390 24,840
PSCo 3,860 2,730 1,650 4,740 3,120 16,100
NSP-Wisconsin 1,190 860 610 510 430 3,600
Other (a)
(130) (170) (80) 10 10 (360)
Total base capital expenditures $ 16,300 $ 14,670 $ 15,190 $ 13,070 $ 10,770 $ 70,000
(a)Other category includes intercompany transfers for equipment with long lead times.
Base Capital Forecast (Millions of Dollars)
By Function 2027 2028 2029 2030 2031 Total
Renewables $ 4,820 $ 4,320 $ 6,760 $ 3,800 $ 1,660 $ 21,360
Electric Transmission 3,550 3,630 3,810 3,750 3,820 18,560
Electric Distribution 3,070 2,850 1,770 3,030 2,940 13,660
Electric Generation 3,150 2,510 1,450 1,070 1,030 9,210
Natural Gas 840 650 650 810 770 3,720
Other 870 710 750 610 550 3,490
Total base capital expenditures $ 16,300 $ 14,670 $ 15,190 $ 13,070 $ 10,770 $ 70,000
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.
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.
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):
(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)
$ 35,810
New debt (b)
26,190
Equity issuances (c)
8,000
Base capital expenditures 2027-2031 $ 70,000
Maturing Debt $ 5,630
(a)Net of dividends and pension funding.
(b)Reflects a combination of short and long-term debt; net of refinancing.
(c)Amount could include other financing instruments that receive equity credit from the credit rating agencies.
2026 Financing Activity - Xcel Energy and its utility subsidiaries issued the following long-term debt:
Issuer Security Amount Tenor Coupon
Xcel Energy Inc. Junior subordinated notes $ 800 million 30 year 5.75% fixed-to-fixed reset rate
PSCo First mortgage bonds 1,300 million 3 year & 10 year 4.15% & 5.05%
NSP-Minnesota First mortgage bonds 1,200 million 10 year & 30 year 4.85% & 5.55%
NSP-Wisconsin First mortgage bonds 250 million 15 year 5.48%
SPS First mortgage bonds 1,200 million 10 year & 30 year 5.30% & 5.875%
PSCo First mortgage bonds 800 million
10 year (a) & 30 year
5.35% & 6.20%
(a)2024 10 year financing re-opened in 2026. Bonds are due in 2034.
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.
During the nine months ended Sept. 30, 2026, Xcel Energy Inc. entered forward sale agreements for shares of common stock totaling 62.1 million shares (minimum expected proceeds of $4.1 billion). As of Sept. 30, 2026, 79.4 million shares remain unsettled on forward equity agreements and collared forward equity agreements (minimum expected proceeds of $5.8 billion).
Long-Term Borrowings, Equity Issuances and Other Financing Instruments - Xcel Energy may issue equity through its ATM program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.
See Note 4 to the consolidated financial statements for further information.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
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)
Key assumptions as compared with 2025 actual levels unless noted:
•Constructive outcomes in all pending rate case and regulatory proceedings.
•Normal weather patterns for the remainder of the year.
•Weather-normalized retail electric sales are projected to increase ~3%.
•Weather-normalized retail firm natural gas sales are projected to be flat.
•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.
•O&M expenses are projected to increase ~5%.
•Depreciation expense is projected to increase approximately $100 million to $110 million. The decrease from prior guidance is primarily offset by lower revenue.
•Property taxes are projected to increase $30 million to $40 million.
•Interest expense (net of AFUDC - debt) is projected to increase $290 million to $300 million, net of interest income.
•AFUDC - equity is projected to increase $180 million to $190 million. The increase from prior guidance is primarily offset by lower revenue.
Xcel Energy 2027 Earnings Guidance - Xcel Energy's 2027 ongoing earnings guidance is a range of $4.48 to $4.62 per share. (a)
Key assumptions as compared with 2026 actual levels unless noted:
•Constructive outcomes in all pending rate case and regulatory proceedings.
•Normal weather patterns for the year.
•Weather-normalized retail electric sales are projected to increase ~5%.
•Weather-normalized retail firm natural gas sales are projected to increase ~1%.
•Capital rider revenue is projected to increase $560 million to $570 million.
•O&M expenses are projected to increase ~4%.
•Depreciation expense is projected to increase approximately $460 million to $470 million.
•Property taxes are projected to increase $30 million to $40 million.
•Interest expense (net of AFUDC - debt) is projected to increase $320 million to $330 million, net of interest income.
•AFUDC - equity is projected to increase $250 million to $260 million.
(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management's view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
• Deliver long-term annual EPS growth of 6% to 8+% based off of $3.80 per share.
• Deliver annual dividend increases of 4% to 6%.
• Target a dividend payout ratio of 45% to 55%.
• Maintain senior secured debt credit ratings in the "A" range.
Xcel Energy Inc. published this content on October 29, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on October 29, 2026 at 19:31 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]