• First quarter GAAP and ongoing diluted earnings per share were $0.88 in 2024 compared with $0.76 in 2023.
• Xcel Energy reaffirms 2024 EPS guidance of $3.50 to $3.60 per share.

Xcel Energy Inc. (NASDAQ: XEL) today reported 2024 first quarter GAAP and ongoing earnings of $488 million, or $0.88 per share, compared with $418 million, or $0.76 per share in the same period in 2023.

First quarter ongoing earnings results reflect increased recovery of infrastructure investments and lower O&M expenses, partially offset by increased interest charges and depreciation.

“Our thoughts remain with the communities impacted by wildfires in the Texas Panhandle, an area we have served for more than 100 years,” said Bob Frenzel, chairman, president and CEO of Xcel Energy. “Like all energy companies, we are navigating changes in weather and climate-induced impacts on our operations. Wildfire mitigation and system resiliency will continue to be priorities going forward. We have already advanced a number of wildfire risk reduction initiatives — including preventive power shutoffs during high-risk conditions, non-reclose and fast-trip safety settings, and accelerated pole inspections and replacements — and will continue to enhance our wildfire mitigation efforts.”

At 9:00 a.m. CDT today, Xcel Energy will host a conference call to review financial results. To participate in the call, please dial in 5 to 10 minutes prior to the start and follow the operator’s instructions.

The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website at www.xcelenergy.com. To access the presentation, click on Investors under Company. If you are unable to participate in the live event, the call will be available for replay from April 25th through April 29th.

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2024 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2023 and subsequent filings with the Securities and Exchange Commission, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; uncertainty regarding epidemics, the duration and magnitude of business restrictions including shutdowns (domestically and globally), the potential impact on the workforce, including shortages of employees or third-party contractors due to quarantine policies, vaccination requirements or government restrictions, impacts on the transportation of goods and the generalized impact on the economy; effects of geopolitical events, including war and acts of terrorism; cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of 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.

This information is not given in connection with any sale, offer for sale or offer to buy any security.

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Investor Relations Earnings Release (Unaudited)

Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with generally accepted accounting principles (GAAP), as well as certain non-GAAP financial measures such as ongoing return on equity (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 adjusts measures calculated and presented in accordance with GAAP. 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.

Ongoing ROE

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’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.

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 earnings per share, 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. For the three months ended March 31, 2024 and 2023, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

Note 1. Earnings Per Share Summary

Xcel Energy’s first quarter GAAP and ongoing diluted earnings were $0.88 per share, compared with $0.76 per share in the same period in 2023. The increase in earnings per share was primarily driven by increased recovery of infrastructure investments, higher allowance for funds used during construction (AFUDC) and lower O&M expenses, partially offset by increased interest charges and depreciation. 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:

PSCo — GAAP and ongoing earnings were flat for the first quarter primarily reflecting increased recovery of electric infrastructure investments, which was offset by unfavorable weather and increased depreciation and interest charges.

NSP-Minnesota — GAAP and ongoing earnings increased $0.13 per share for the first quarter of 2024. The change was driven by increased recovery of electric and natural gas infrastructure investments and lower O&M expenses, partially offset by higher interest expenses and depreciation.

SPS — GAAP and ongoing earnings were flat for the first quarter of 2024 primarily due to regulatory rate outcomes and lower O&M expenses, offset by increased depreciation and amortization expenses.

NSP-Wisconsin — GAAP and ongoing earnings were flat for the first quarter of 2024 as lower O&M expenses were offset by increased depreciation.

Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from Energy Impact Partners (EIP) funds equity method investments. The decline in earnings is largely due to increased interest rates.

Components significantly contributing to changes in 2024 EPS compared to 2023:

Note 2. Regulated Utility Results

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 mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.

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.

Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:

Sales — Sales growth (decline) for actual and weather-normalized sales in 2024 compared to 2023:

Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date

• PSCo — Residential sales decreased due to a 1.5% decrease in use per customer, partially offset by customer growth of 1.3%. The C&I sales decline was related to decreased use per customer, primarily in the information and professional services sectors, partially offset by increases in the manufacturing and health care sectors.
• NSP-Minnesota — Residential sales decreased due to a 3.5% decrease in use per customer, partially offset by a 1.5% increase in customers. C&I sales declined due to decreased use per customer, largely in the manufacturing sector.
• SPS — Residential sales declined as a result of a 4.6% decrease in use per customer, partially offset by 0.5% customer growth. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
• NSP-Wisconsin — Residential sales declined due to a 4.9% decrease in use per customer, partially offset by 0.8% increase in customers. C&I sales decline was associated with decreased use per customer, experienced largely in the professional services and manufacturing sectors.

Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date

• Increase in natural gas sales was driven by continued strength in PSCo residential and C&I use per customer. Additionally, overall residential and C&I customer growth was 1.1% and 0.6%, respectively.

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. In the first quarter, electric revenues decreased $78 million.

Natural Gas Revenues — Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes. In the first quarter, natural gas revenues decreased $347 million.

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality. However, these incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues and have minimal earnings impact.

Electric fuel and purchased power expenses decreased $169 million for the first quarter of 2024. The decrease is primarily due to lower commodity prices, timing of fuel recovery and decreased volumes.

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 generally offset in operating revenues and have minimal earnings impact.

Natural gas sold and transported decreased $361 million for the first quarter of 2024. The decrease is primarily due to lower commodity prices and volumes.

O&M Expenses — O&M expenses decreased $45 million for the first quarter. The decrease was primarily due to decreased labor and benefit costs, gain on land sale and lower bad debt expenses.

Depreciation and Amortization — Depreciation and amortization increased $34 million for the first quarter as a result of system expansion, offset by depreciation life extensions implemented in the Minnesota Electric Rate Case.

Interest Charges — Interest charges increased $38 million for the first quarter, largely due to increased long-term debt levels and higher interest rates.

AFUDC, Equity and Debt — AFUDC increased $22 million for the first quarter driven by increased investment in renewable projects in 2024.

Income Taxes — Effective income tax rate:

Note 3. Capital Structure, Liquidity, Financing and Credit Ratings

Xcel Energy’s capital structure:

Liquidity — As of April 22, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

Credit Ratings — Access to the capital markets at reasonable terms is partially dependent on credit ratings. The following ratings reflect the views of Moody’s, S&P Global Ratings and Fitch. The highest credit rating for debt is Aaa/AAA and the lowest investment grade rating is Baa3/BBB-. The highest rating for commercial paper is P-1/A-1/F-1 and the lowest rating is P-3/A-3/F-3. A security rating is not a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Credit ratings and long-term outlook assigned to Xcel Energy Inc. and its utility subsidiaries as of April 22, 2024:

2024 Financing Activity — During 2024, Xcel Energy Inc. and its utility subsidiaries anticipate the following long-term debt issuances:

Xcel Energy may issue equity through its at-the-market 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.

Note 4. Rates, Regulation and Other

NSP-Minnesota — 2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the Minnesota Public Utilities Commission (MPUC) for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In December 2023, the MPUC approved NSP-Minnesota’s request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).

On April 19, 2024, four parties filed direct testimony. The DOC, OAG, and CUB were the only parties to quantify recommended financial adjustments. The OAG and CUB provided limited comments, recommending a reduction of approximately $1 million of O&M expenses each. The CUB additionally recommended a reduction to ROE.

Proposed DOC modifications to NSP-Minnesota’s request were as follows:

Positions on NSP-Minnesota’s filed rate request were as follows:

Procedural schedule:

• Mediation: May 17, 2024 (day subject to availability)
• Rebuttal testimony: May 24, 2024
• Evidentiary hearings: July 10-12, 2024
• ALJ report: October 28, 2024
• MPUC Order Due: March 14, 2025

NSP-Minnesota — Upper Midwest Resource Plan — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC which included the following key items:

• Reduced carbon emissions by more than 80%, potentially up to 88%, by 2030.
• Extends the operation of Prairie Island and Monticello through the early 2050s.
• Adds 3,600 MWs of new wind and solar resources by 2030.
• Adds 600 MWs of battery energy storage by 2030.
• Adds more than 2,200 MWs of dispatchable resources by 2030.

These proposed resources are in addition to projects already approved by the MPUC. NSP-Minnesota anticipates a MPUC decision in 2025.

NSP-Minnesota — North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) seeking an increase in natural gas rates of $8.5 million (9.4%), a 2024 test year, ROE of 10.20%, an equity ratio of 52.5% and rate base of $168 million. In February 2024, the NDPSC approved interim rates of $8 million, effective March 1, 2024.

PSCo - Colorado Natural Gas Rate Case — In January 2024, PSCo filed a request with the Colorado Public Utilities Commission (CPUC) seeking an increase to retail natural gas rates of $171 million, or an approximately 9.5% increase in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% and a $4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023. PSCo has requested a proposed effective date of Nov. 1, 2024.

PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following the expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.

Procedural schedule:

• Intervenor testimony: July 11, 2024
• Rebuttal testimony: Aug. 15, 2024
• Settlement deadline: Aug. 27, 2024
• Evidentiary hearing: Sept. 4-12, 2024
• Statement of position: Sept. 26, 2024

PSCo — Colorado Resource Plan — In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs. PSCo expects to invest approximately $4.8 billion in generation resources under the portfolio for the benefit of its customers and achieving the state’s clean energy goals.

In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in related proceedings throughout 2024.

In March 2024, PSCo filed its first certificate of need (CPCN) for the Rocky Mountain and Arroyo 2 solar projects on an expedited basis in order to begin construction in time for planned in-service dates in 2025 and 2026. PSCo expects to file additional generation and transmission CPCNs throughout the remainder of 2024.

PSCo — Transportation Electrification Plan — In April 2024, the CPUC approved PSCo’s TEP with modification, including a three-year budget of $264 million and continued cost recovery through the TEP rider. The CPUC approved PSCo’s proposal to offer rebates for residential chargers and wiring to be paired with residential managed charging programs and vehicle rebates for Income-Qualified customers, as well as its proposal to offer rebates for commercial public chargers and electric vehicle supply infrastructure. Additionally, the CPUC approved PSCo’s proposed budget to support innovation projects including electric school buses, Vehicle-to-Everything demonstrations, and stakeholder-driven projects with a focus on disproportionately impacted communities. The Commission also approved a WACC return on rebates with a 3-year amortization.

PSCo — Wildfire Mitigation Plan — PSCo will file a Wildfire Mitigation Plan and request for recovery of costs to execute the plan in the second quarter of 2024. The plan will include a number of new and expanded programs from the currently approved Wildfire Mitigation Plan including distribution undergrounding, distribution covered conductor, enhanced wildfire safety settings, increased scope and scale for vegetation management, updated frequency of inspections of poles and other equipment in wildfire risk zones, transmission line rebuilds, proactive line de-energization and situational awareness programs including weather stations, cameras, and other monitoring software.

PSCo — CPUC Proactive Line De-Energization Investigation — In early April 2024, PSCo proactively de-energized certain lines in Colorado due to winds that were over 90 MPH to reduce potential wildfire risk. Later in April, the CPUC opened a Miscellaneous Proceeding to seek information on:

• Utility operations during, after, and leading up to the wind event to identify risks, de-energize lines and re-energize lines.
• Customer communications (including what was communicated to whom and when).
• Community engagement to assess the coordination with neighboring electric providers, telecom companies, 911, medical providers, and other first responders and community leaders.

The CPUC held sessions to hear public comments and will hold Commissioner Information Meetings in May 2024 to hear directly from PSCo, impacted customers, and other first responders and community leaders on power shutoffs. A potential order, rules, procedures or report is expected later this year.

SPS — 2023 Texas Electric Rate Case — In 2023, SPS filed an electric rate case with the Public Utility Commission of Texas (PUCT) seeking an increase in base rate revenue of $158 million (14%).

The request was based on a ROE of 10.65%, an equity ratio of 54.6%, a retail rate base of $3.6 billion and a change in the Tolk coal plant depreciation life from 2034 to 2028.

In December 2023, SPS, PUCT Staff and intervenors filed a black box settlement. Key terms include:

• A base rate increase of $65 million effective back to July 13, 2023.
• A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction and in other proceedings filed before the PUCT where a stated WACC is required.
• The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028.
• Establishment of a rate rider of approximately $18 million to be recovered over a three-year period for various deferred expenses.

Interim rates based on the settlement went into effect on Feb. 1, 2024. On April 11, 2024, the PUCT unanimously approved the settlement without modification.

SPS New Mexico 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. Based on load forecast scenarios, SPS’ initial IRP modeling projects a total resource need ranging from approximately 5,300 MW to 10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP. SPS expects to issue an RFP for new generation in July 2024. The RFP will be evaluated in the latter half of 2024 with portfolio selection expected in early 2025.

Note 5. Wildfire Litigation

2024 Smokehouse Creek Fire Complex — Beginning on February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which news reports indicate burned into the perimeter of the Smokehouse Creek Fire (together, referred to herein as the “Smokehouse Creek Fire Complex”). The Texas A&M Forest Service issued incident reports that determined that the Smokehouse Creek Fire and the 687 Reamer Fire were caused by power lines owned by SPS after wooden poles near each fire origin failed. SPS is continuing to conduct investigations into other potential ignitions associated with the Smokehouse Creek Fire Complex. According to the Texas A&M Forest Service’s Incident Viewer and news reports, as of March 19, 2024, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres.

On March 12, 2024, the Speaker of the Texas House of Representatives created the Investigative Committee on the Panhandle Wildfires (the “Investigative Committee”). The Investigative Committee held public hearings in Pampa, Texas, between April 2 and April 4, 2024, and stated that it plans to issue a report by early May 2024.

SPS is aware of approximately 15 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex, including one putative class action on behalf of persons or entities who owned rangelands or pastures that were damaged by the fire. The complaints generally allege that SPS’ equipment ignited the Smokehouse Creek Fire Complex and seek compensation for losses resulting from the fire, asserting various causes of action under Texas law. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. SPS has also received approximately 46 claims for losses related to the Smokehouse Creek Fire Complex through its claims process.

Texas law does not apply strict liability in determining an electric utility company’s liability for fire-related damages. For negligence claims under Texas law, a public utility has a duty to exercise ordinary and reasonable care.

Potential liabilities related to the Smokehouse Creek Fire Complex depend on various factors, including the cause of the equipment failure and the extent and magnitude of potential damages, including damages to residential and commercial structures, personal property, vegetation, livestock and livestock feed (including replacement feed), personal injuries and any other damages, penalties, fines or restitution that may be imposed by courts or other governmental entities if SPS is found to have been negligent.

Based on the current state of the law and the facts and circumstances available to Xcel Energy as of the date of this filing, Xcel Energy believes it is probable that it will incur a loss in connection with the Smokehouse Creek Fire Complex and accordingly recorded a pre-tax charge in the amount of $215 million for the three months ended March 31, 2024 (before available insurance). The aggregate liability of $215 million for claims in connection with the Smokehouse Creek Fire Complex (before available insurance) corresponds to the lower end of the range of Xcel Energy’s reasonably estimable range of losses, and is subject to change based on additional information. This $215 million estimate does not include, among other things, amounts for (i) potential penalties or fines that may be imposed by governmental entities on Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation claims by federal, state, county and local government entities or agencies, (iv) compensation claims for damage to trees, railroad lines, or oil and gas equipment, or (v) other amounts that are not reasonably estimable.

Xcel Energy is unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability. In the event that SPS or Xcel Energy Services Inc. was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows.

The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change.

SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. As of March 31, 2024, SPS has recorded an insurance receivable for $215 million. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.

Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (the “Sheriff’s Report”). According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.

According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.

The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition.

PSCo is aware of 302 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,047 plaintiffs, and one complaint is filed on behalf of a putative class of first responders who allegedly were exposed to the threat of serious bodily injury, or smoke, soot and ash from the Marshall Fire. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages.

In September 2023, the Boulder County District Court Judge consolidated eight lawsuits that were pending at that time into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025. Discovery is now underway.

Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, Colorado courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated.

Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages.

In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire.

Note 6. Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2024 Earnings Guidance — Xcel Energy’s 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.^(a)

Key assumptions as compared with 2023 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 1% to 2%.
• Weather-normalized retail firm natural gas sales are projected to be flat.
• Capital rider revenue is projected to increase $60 million to $70 million (net of PTCs).
• O&M expenses are projected to increase 1% to 2%.
• Depreciation expense is projected to increase approximately $290 million to $300 million. The change largely reflects changes in depreciation rates approved in the Texas rate case, which are largely offset in revenue and earnings neutral.
• Property taxes are projected to increase $20 million to $30 million.
• Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income.
• AFUDC - equity is projected to increase $65 million to $75 million.
• ETR is projected to be ~(4%) to (6%). The negative ETR is largely offset by PTCs flowing back to customers in the capital riders and fuel mechanisms and is largely earnings neutral. The projected ETR does not reflect the potential impact of nuclear PTCs, which are also expected to flow back to customers.

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 5% to 7% based off of a 2023 actual ongoing earnings base of $3.35 per share.
• Deliver annual dividend increases of 5% to 7%.
• Target a dividend payout ratio of 50% to 60%.
• Maintain senior secured debt credit ratings in the A range.

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