XEL 10-K & 10-Q changes, risk factors and insider trading

•Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patternspatterns.

•IncreasedRisks costsassociated due towith aging infrastructure.

Our utility operationsoperations, resource adequacy and system reliability are subject to long-term planning and project risks.

Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technologytechnology, equipment availability and public policy. Xcel Energy’s long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.

In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., the addition of large loads, increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency or other reductions in expected sales growth could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. Additionally, increasing uncertainty surrounding federal policy to renewable deployment could negatively impact wind, solar and storage development.

The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Enterprise level financial and customer billing technology systems may be unable to support the increasing customer complexity. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.

Our utilities have physical and financialsignificant risks associated with wildfires.

In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in availability of vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other environmental factors have increased both the frequency and duration of thefire wildfireweather seasonconditions and the potential impact of an event. Also, theThe expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. WildfiresAlso, wildfires could jeopardize Xcel Energy’s electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. Our current wildfire mitigation initiatives may not be effective in preventing or reducing ignitions and wildfire-related losses.

While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages,damage amounts could potentially exceed our coverage (as experienced with the Marshall Wildfire settlement in 2025) and negatively impact our results of operations, financial condition or cash flows.

A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations.

DueAdditionally, due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that itsour risk management programs andmay procedures wouldnot be effective to protect against all significant adverse market deviations.fluctuations and our results of operations, financial condition or cash flows could be materially impacted.

We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Also, suppliers of key assets critical to long-term planning may be limited, creating vendor concentration risk that could increase costs and negatively impact investment execution.

OurActions of our employees, directors, third-party contractors,contractors or suppliers maycould violateexpose or be perceivedus to violatereputational our Codes of Conduct, which could have an adverse effect on our reputation.risks.

Our profitability depends on the ability of our utility subsidiaries to recover their costs,costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.

AdverseRegulators regulatorymay rulingschallenge (rate increases due to increased customer affordability pressures. Public policy developments, including legislative actions and electoral changes inat the state level, may affect recovery mechanisms) or theallowed impositionreturns ofand additionalmay regulationslimit couldrecovery timing or cost allocation, negatively impactimpacting our results of operations, financial condition or cash flows.

The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations.

If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.

Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generationoperational facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.

While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. The potential for unprecedented load growth and the need for additional generation resources to support such growth may further impact the timing or achievement of our climate goals. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, 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 is adjusted fromadjusts measures calculated and presented in accordance with GAAP.

Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’sstockholders’ equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.

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 the net income or loss of each subsidiary,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 offor such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.

(ab)Amounts may not add due to rounding.

Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In 2024,October 2024 following contested case procedures, Xcelthe EnergyMPUC recognizedordered a customer refund of $47$46 million for replacement power incurred during the outage.outage, which is presented as a non-recurring charge to electric revenues.

ComancheMarshall Unit 3Wildfire Litigation — In the third quarter of 2023,2025, PSCo recognized a non-recurring $34$287 million charge as a result of a jurysettlement verdictreached with the plaintiffs in Denverthe CountyMarshall DistrictWildfire Courtlitigation. awardingIn COREthe Electricfourth Cooperativequarter lostof power2025, damagesan additional $12 million was recognized for estimated remaining settlement costs as well as legal and other costs.

Xcel Energy — GAAP diluted earnings were $3.44$3.42 per share compared to $3.21$3.44 per share in 20232024 and ongoing diluted earnings were $3.80 per share in 2025, compared with $3.50 per share in 2024, compared with $3.35 per share in 2023.2024. The change in ongoing EPS was driven by increased recovery of infrastructure investments,investments and electric sales growth, partially offset by higher depreciation,interest, interest chargesdepreciation and O&M expenses.

NSP-Minnesota — GAAP earnings increased $0.13$0.12 per share and ongoing earnings increased $0.15$0.06 per share for 20242025 compared to 2023.2024. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased O&M expenses, depreciation and interest charges.

PSCo — GAAP earnings increaseddecreased $0.13$0.24 per share and ongoing earnings increased $0.06$0.14 per share for 2024.2025 Higher(difference in GAAP and ongoing due to Marshall Wildfire settlement in 2025, see Non-GAAP Financial Measures for reconciliation from GAAP to ongoing earnings). primarilyOngoing reflectsearnings increased due to higher recovery of electric and natural gas infrastructure investments,investments and increased AFUDC, which was partially offset by increased depreciation, interest and O&M and interest charges.

NSP-WisconsinSPS — GAAP and ongoing earnings decreased $0.01$0.03 per share for 2024.2025 . The decrease in ongoing earnings was primarilydriven aby resultincreased interest charges, O&M expenses and the negative impact of weather, partially offset by sales growth and higher depreciation.recovery of electric infrastructure investments.

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 declinechange in earnings for 2024 is largelywas due to highergains on debt levels and increased interest rates,repurchases, partially offset by ahigher gaininterest onrates and debt repurchases.levels.

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.

•NSP-Minnesota — Residential sales declinedincreased due to acustomer 1.5%growth decrease(1.1%) inand use per customer,customer partially offset by a 1.4% increase in customers.(0.4%). The declinedecrease in C&I sales was due to lower use per customer, particularly in the manufacturing sector.customer.

•PSCo — Residential sales increased due to acustomer 1.4%growth increase(1.1%) in customers, partially offset by a 0.7% decrease inand use per customer.customer (0.6%). The declineincrease in C&I sales was attributabledue to decreasedhigher use per customer, particularly in the wholesale tradeinformation and mining.energy sectors.

•SPS — Residential sales declinedincreased due to a 2.2% decrease inincreased use per customer partially(3.6%) offsetand bycustomer agrowth (0.7%). The increase in customers. C&I sales increasedwas due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining.sector.

•NSP-Wisconsin — Residential sales declinedincreased due to a 2.7% decrease inincreased use per customer,customer offset(1.1%) byand acustomer 1.0%growth (0.9%). The increase in customers. The C&I sales decline was associateddue withto lowercustomer use per customer, experienced particularly in the professional services and manufacturing sectors.growth.

•NaturalDecrease in natural gas sales reflectwas 1.7%driven residentialprimarily by decreased use per customer andin 1.4% C&I use per customer decreases. Partially offsetting these were increasedPSCo residential and C&II, customerspartially offset by customer growth in all jurisdictions.

Electric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes.

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 decreasedincreased $490$173 million in 2024.2025. The decreaseincrease is primarily due to timingincreased ofcommodity fuel recovery mechanismsprices and lowertransmission commodity prices, partially offset by increased volumes.expense.

Natural gas sold and transported decreasedincreased $505$90 million in 2024.2025. The decreaseincrease is primarily due to lowerincreased commodity prices and volumes.volumes, partially offset by timing of fuel recovery mechanisms.

O&M Expenses — O&M expenses increased $96$192 million in 20242025 primarily due to operationalincreased activities,benefits includingand generationhealthcare maintenance, storm response,costs, wildfire mitigation costs and damage prevention. The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially(largely offset byin lowernon-fuel laborrider andrevenue), benefitnuclear generation costs and lowerinsurance bad debt expenses.costs.

Depreciation and Amortization — Depreciation and amortization increased $296$209 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions.investment.

Other Income — Other income increased $121$92 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gaingains on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation.repurchases.

Interest Charges — Interest charges increased $200$213 million in 2024.2025. The increase was largely due to higher long-term and short-term debt levels to fund capital investments and higher interest rates.

AFUDC, Equity and Debt — AFUDC increased $99$165 million in 2024. This increase was largely2025, due to increasedsystem investment in renewable and transmission projects.investment.

(a)Amounts primarily include gaingains from open market debt repurchasesrepurchases, inpartially 2024.offset by taxes.

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate.WGI. 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.

In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. TheIn opinionJune is currently pending further action from2025, the MPUC.MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026.

2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years,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. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective JanuaryJan. 1, 2025. AIn decisionMarch is2025, expectedNSP-Minnesota infiled 2026.supplemental direct testimony, updating its total revenue request to $473 million.

20242025 NorthSouth Dakota Electric Rate Case — In DecemberJune 2024,2025, NSP-Minnesota filed a request with the NDPSCSDPUC for ana net annual electric rate increase of approximately$44 $45million million, or 19.3% over current rates established in 2021.(15%). The filing is based on a 20252024 forecasthistoric test year and includesyear, a requested ROE of 10.3%, rate base of approximately $817$1.2 millionbillion and an equity ratio of 52.5%.52.87%. InInterim Januaryrates 2025,were the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb.Jan. 1, 2025).2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.

Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of 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.

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. AThe MPUC ordered the ALJ-recommended disallowance in May 2026. Total non-recurring chargecharges of $37$38 million waswere recorded to electric revenues induring the firstsix quartermonths ofended June 30, 2026 for incremental customer refunds, including interest.

Marshall Wildfire Litigation — In the firstsix quartermonths ofended June 30, 2026, PSCo recognized a $22$19 million reductionof net reductions to operating expenses due primarily to an increase in the estimated amount recoverable from insurance for non-recurring Marshall Wildfire costs.

Xcel Energy’s firstsecond quarter diluted GAAP and ongoing earnings were $0.89$0.93 per share compared with $0.84$0.75 per share in the same period in 20252025. andThe ongoing earnings were $0.91 compared with $0.84 per sharechange in 2025. Despite the impact of unseasonably warm weather in the first quarter, ongoing earnings per share was primarily driven by increased recovery of electric infrastructure investments and electric sales growth,investments, partially offset by higher financing costs and increased depreciation expense.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).

NSP-MinnesotaPSCo — GAAP and ongoing earnings decreasedincreased $0.02$0.06 per share for the second quarter of 2026. Year-to-date GAAP earnings increased $0.03 per share and ongoing earnings increased $0.02$0.01 per share for the first quarter of 2026.share. The increase in year-to-date ongoing earnings increase was driven by higher recovery of electric and natural gas infrastructure investments,investments which was partially offset by increasedunfavorable interest charges.weather. The difference between GAAP and ongoing earnings was driven by recognitionan ofincrease customer refunds related toin the 2023-2024estimated Prairieamount Islandrecoverable nuclearfrom facilityinsurance outage.for Marshall Wildfire costs.

NSP-WisconsinNSP-Minnesota — GAAP and ongoing earnings increased $0.03$0.05 per share for the firstsecond quarter of 2026. Year-to-date GAAP earnings increased $0.03 per share and ongoing earnings increased $0.07 per share. The changeyear-to-date ongoing earnings increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciationinterest expense.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.

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.

Percentage increase (decrease) in normal and actual HDDHDD, CDD and THI:

Sales — Sales growth (decline) for actual and weather-normalized sales volumes in 2026 compared to 2025:

•C&I sales — Increase is due to higher use per customer in SPS (10.6%6.0%) and NSP-Minnesota (1.8%2.0%) and customer growth in NSP-Wisconsin (1.1%1.0%). Increased activity in the energy sector in SPS and variousthe sectorsmanufacturing sector in all jurisdictions contributed to the sales growth.

•IncreaseDecrease in natural gas sales was driven primarily by customer growth in all jurisdictions, partially offset by decreasedreduced use per customer forin C&Imost jurisdictions and residentialcustomer customers in PSCo and NSP-Wisconsin.classes.

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Electric fuel and purchased power expenses decreased $1$240 million for the firstsecond quarter of 2026.2026 and $241 million year-to-date. The year-to-date change was primarily due to lower commodity prices, largely in SPS..

Natural gas sold and transported increaseddecreased $7$41 million for the firstsecond quarter of 2026.2026 and $34 million year-to-date. The year-to-date change was primarily due to higherdecreased commodityvolumes pricesin PSCo, partially offset by decreasedhigher volumescommodity in PSCo.prices.

O&M Expenses — O&M expenses decreasedincreased $11$16 million for the firstsecond quarter of 2026.2026 and $5 million year-to-date. The year-to-date change was primarily due to lowerincreased benefitsgeneration and bad debt expenses.costs.

Depreciation and Amortization — Depreciation and amortization increaseddecreased $40$60 million for the firstsecond quarter of 2026.2026 and $20 million year-to-date. The year-to-date change was largelyprimarily due to the resultrecognition of 2025 and 2026 depreciation reductions (nuclear life extensions) in the second quarter of 2026, partially offset by system investment.expansion.

Interest Charges — Interest charges increased $80$94 million for the firstsecond quarter of 2026,2026 largelyand $174 million year-to-date. The year-to-date change was primarily due to higher debt levels and interest rates.levels.

AFUDC, Equity and Debt — AFUDC increased $61$54 million for the firstsecond quarter of 2026,2026 largelyand the$115 resultmillion ofyear-to-date. The year-to-date change was primarily due to system investment.

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,efforts and the cost of capital.

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 MarchOctober 2025, NSP-Minnesota filed supplemental directrebuttal testimony, updating its total revenue request to $473$365 million.

A final written MPUC decisionorder is expected inby theJuly third quarter of31, 2026.

AAn ALJ report is expected by September 2026 and a MPUC decision is expected in November 2026.

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. AIn commissionJuly decision2026, onthe MPUC declined to modify the treatment of prepaid pension asset is expected in mid-2026.asset.

2025 South Dakota Electric Rate Case — In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, an equity ratio of 52.87% and rate base of approximately $1.2 billion. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.

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. AIn May 2026, the SDPUC decision is expected inapproved the secondsettlement quarteragreement, ofand rates became effective July 1, 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.

•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.

•In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued an RFP seeking up to 3,500 MW of wind, solar, hydro, standalone storage, or hybrid capacity that will achieve commercial operation by December 31, 2030. Additionally,Short-listed NSP-Minnesota is seeking to procure up to 600 MW of solar or solar plus storage capacity that will achieve commercial operation by December 31, 2029, and meet Minnesota’s Distributed Solar Energy Standard eligibility requirements. Bidsprojects were submittedannounced in MarchJune 2026, and filing for requisite regulatory approval is expected by the end of 2026.

Large Load Agreement — In the first quarter of 2026, NSP-Minnesota entered into an electric service agreement to power a new Google data center in Minnesota. Under the agreement, Google will pay all costs for its new service for the duration of the agreement,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 Electricelectric Serviceservice Agreement,agreement, including a proposed Clean Energy Accelerator Charge for 1,900 MW of clean energy resources, was filed with the MPUC in April 2026. ApprovalsA fordecision 1,000 MW of resources for the Clean Energy Accelerator program are pending as part of existing resource acquisition processes. The remaining resources areis expected to be requested in thoseearly processes by the end of 2026.2027.