• Second quarter GAAP and ongoing diluted earnings per share were $0.54 in 2024 compared with $0.52 in 2023.
• Xcel Energy reaffirms 2024 EPS guidance of $3.50 to $3.60 per share.

Xcel Energy Inc. (NASDAQ: XEL) today reported 2024 second quarter GAAP and ongoing earnings of $302 million, or $0.54 per share, compared with $288 million, or $0.52 per share in the same period in 2023.

Second quarter ongoing earnings reflect recovery of increased infrastructure investments and warmer than normal weather, partially offset by increased depreciation, interest charges and O&M expenses.

“Xcel Energy continues to meet the growing demand for energy from our customers while driving forward the clean energy transition and adapting to changing regulatory and environmental conditions,” said Bob Frenzel, chairman, president and CEO of Xcel Energy. “We are reaffirming our earnings guidance of $3.50 - $3.60 per share.”

“We continue to advance proposals to enhance the resiliency and sustainability of our system for the safety and benefit of our customers. In Colorado, we filed an updated Wildfire Mitigation Plan that builds upon our existing investments,” Frenzel said. “We also supported legislation that will help the state achieve a smoother clean energy transition by enhancing the distribution system planning process in Colorado. And in Minnesota, we collaborated with stakeholders to achieve a settlement in our natural gas rate case that supports improvements while keeping our residential customers’ natural gas rates below the national average.”

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 Aug. 1^st through Aug. 5^th.

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, expected pension contributions, and expected impact on our results of operations, financial condition and cash flows of interest rate changes, increased credit exposure, and legal proceeding outcomes, 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 and six months ended June 30, 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 second quarter GAAP and ongoing diluted earnings were $0.54 per share, compared with $0.52 per share in the same period in 2023. The increase in earnings per share was primarily driven by increased recovery of infrastructure investments and warmer than normal weather, partially offset by higher depreciation, interest charges and O&M expenses. 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:

NSP-Minnesota — GAAP and ongoing earnings increased $0.01 per share for the second quarter and $0.13 year-to-date. Year-to-date earnings primarily reflect increased recovery of electric and natural gas infrastructure investments and lower O&M expenses, partially offset by higher depreciation.

PSCo — GAAP and ongoing earnings increased $0.04 in the second quarter and $0.05 year-to-date. The year-to-date change was driven by increased recovery of electric infrastructure investments, which was partially offset by increased depreciation.

SPS — GAAP and ongoing earnings increased $0.01 for the second quarter and year-to-date as regulatory rate outcomes and increased sales and demand were partially offset by increased depreciation.

NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 in the second quarter and year-to-date, largely due to unfavorable weather and increased depreciation.

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 decline in earnings is largely due to increased interest rates and higher debt levels.

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 1.6% 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 manufacturing, information and real estate sectors.

• NSP-Minnesota — Residential sales decreased due to a 2.1% 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 2.9% 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 3.6% 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 residential and C&I customer growth in all jurisdictions and increased use per customer in PSCo. 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.

Natural Gas Revenues — Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.

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. 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 $175 million for the second quarter and $344 million year-to-date. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices.

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 $52 million for the second quarter and $413 million year-to-date. The decrease is primarily due to lower commodity prices and volumes.

O&M Expenses — O&M expenses increased $34 million for the second quarter and decreased $11 million year-to-date. The year-to-date decrease was primarily due to decreased labor and benefit costs, gain on a land sale in the first quarter and lower bad debt expenses, partially offset by recognition of previously deferred costs associated with the Texas Electric Rate Case and planned generation outages that both occurred in the second quarter, as well as increased wildfire mitigation costs.

Depreciation and Amortization — Depreciation and amortization increased $138 million for the second quarter and $172 million year-to-date. The year-to-date increase was largely the result of system expansion as well as recognition of previously deferred costs and depreciation rate changes associated with the Texas Rate Case, partially offset by wind and nuclear life extensions implemented in 2023 in the Minnesota Electric Rate Case.

Interest Charges — Interest charges increased $51 million for the second quarter and $89 million year-to-date, largely due to increased debt levels and higher interest rates.

AFUDC, Equity and Debt — AFUDC increased $24 million for the second quarter and $46 million year-to-date, driven by increased investment in renewable and transmission projects.

Income Taxes — Effective income tax rate:

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

Xcel Energy’s capital structure:

Liquidity — As of July 30, 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 July 30, 2024:

2024 Financing Activity — During 2024, Xcel Energy Inc. and its utility subsidiaries issued the following long-term debt. No further debt issuances are planned for 2024.

Xcel Energy issued approximately $93 million of equity through its at-the-market program through June 2024.

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 a 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).

In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms:

• Natural gas rate increase of $46 million, or 7.5%.
• ROE of 9.6%.
• Equity ratio of 52.5%.
• Rate base of $1.25 billion.
• No change to Commission approved decoupling.

A MPUC decision and order is expected by the end of 2024.

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%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In February 2024, the NDPSC approved interim rates of $8 million, effective March 1, 2024.

In June 2024, the North Dakota staff filed testimony and recommended a $6.3 million increase (7%), based on a ROE of 9.8% and a 50% equity ratio.

The procedural schedule is as follows:

• Surrebuttal testimony: Aug. 12-26, 2024
• Evidentiary hearings: Sept. 3-5, 2024

A NDPSC decision is expected by year-end.

NSP-Minnesota — Minnesota 2023 Fuel Clause Adjustment — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC, with a proposed refund of $126 million for fuel over-recoveries in 2023. In April 2024, the Department of Commerce (DOC) recommended the MPUC approve the non-nuclear aspects of the petition.

In May 2024, the DOC and Minnesota Office of Attorney General (OAG) filed comments relating to an outage at the Prairie Island generating station that lasted from October 2023 through February 2024. The DOC recommended that NSP-Minnesota refund $20 million of replacement power costs for 2023 as well as a future refund of replacement power costs for 2024 once those costs are known. The OAG recommended that NSP-Minnesota refund $18 million of replacement power costs for 2023 and did not address 2024.

In July 2024, NSP-Minnesota filed reply comments in the 2023 proceeding in support of its position that no customer refund for replacement power costs is warranted. A final decision by the MPUC is expected in late 2024.

NSP-Minnesota — Sherco Unit 3 — In May 2024, the Administrative Law Judge (ALJ) recommended a customer refund of $34 million (less a portion of the proceeds received from the settlement with GE) related to purchase power costs incurred during a Sherco Unit 3 outage in 2011. The ALJ indicated that consideration of the $22 million of previously disallowed costs was not in the scope of their recommendation. Xcel Energy has recorded an estimate for a customer refund in this matter. A final decision by the MPUC is expected in late 2024.

NSP-Wisconsin — Wisconsin 2025 Stay-Out Proposal — In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the Public Service Commission of Wisconsin. The filing proposes to offset $28 million and $3 million of the Company’s forecasted 2025 electric and natural gas revenue deficiency, respectively, by amortizing Inflation Reduction Act (IRA) deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two gas capital projects. The Company expects to have a Commission decision before year-end 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 (9.5%). The request is based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year 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 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.

In July 2024, three intervenors filed testimony, with CPUC Staff (Staff) and the Utility Consumer Advocate (UCA) filing comprehensive testimony. Staff and UCA opposed the deferral of collections until Feb. 15, 2025, instead proposing Nov. 1, 2024 as the effective date for new rates.

Proposed modifications:

Procedural schedule:

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

A CPUC decision is expected in the fourth quarter of 2024.

PSCo — Wildfire Mitigation Plan — In June 2024, PSCo filed an Updated Wildfire Mitigation Plan (the Plan) and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion. A CPUC decision is expected in early 2025.

The Plan is a key component of keeping our customers and communities safe while providing reliable and affordable electric service. The Plan integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner under four core programs that include the following:

• Situational awareness – Meteorology, area risk mapping and modeling, artificial intelligence cameras and continuous monitoring.
• Operational mitigations – Enhanced powerline safety settings and public safety power shutoffs (PSPS).
• System resiliency – Asset assessment and remediations, pole replacements, line rebuilds, targeted undergrounding and vegetation management.
• Customer support – Coordination and real-time data sharing with customers and other stakeholders and PSPS resiliency rebates.

Total capital investments and O&M expenses associated with the proposed plan are estimated at the following:

PSCo — Clean Heat Plan — In August of 2023, PSCo filed a Clean Heat Plan to reduce natural gas local distribution company greenhouse gas emissions. PSCo proposed a diversified portfolio of electrification, efficiency and lower-carbon gas options that would create an emissions reduction pathway through 2028 consistent with achieving a 2030 target reduction of 22 percent.

In June 2024, the CPUC approved a portfolio weighted predominantly toward electrification and efficiency programs, based on a budget of $441 million through 2027. The CPUC’s approval included rider cost recovery. The CPUC directed PSCo to file the next Clean Heat Plan in 2026.

SPS — New Mexico Resource Plan (IRP) — In October 2023, SPS filed its IRP with the New Mexico Public Regulation Commission (NMPRC), which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. SPS’ initial IRP modeling projected resource needs ranging from approximately 5,300 MW to 10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP.

In July 2024, SPS issued a request for proposal (RFP), seeking approximately 3,000 MW of accredited generation capacity by 2030. The total capacity to be added to the system is expected to align with the approximate range identified in the SPS IRP, depending on the types of resources proposed in the RFP and their accredited capacity factors.

The RFP will be evaluated in the first quarter of 2025. SPS is expected to file for a certificate of need for the recommended portfolio in the summer of 2025. The Texas and New Mexico Commissions are expected to rule on the recommended portfolio in 2026.

Note 5. Wildfire Litigation

2024 Smokehouse Creek Fire Complex — On February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which 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. According to the Texas A&M Forest Service’s Incident Viewer and news reports, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres.

SPS is aware of approximately 21 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’s 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 141 claims for losses related to the Smokehouse Creek Fire Complex through its claims process and has reached final settlements on 43 of those claims. In July 2024, SPS reached a settlement of a complaint related to one of the two fatalities believed to be associated with the Smokehouse Creek Fire Complex.

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 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 has accrued a $215 million estimated loss for the matter (before available insurance), presented in other current liabilities as of June 30, 2024.

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 remains 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. SPS has recorded an insurance receivable for $215 million, presented within prepayments and other current assets as of June 30, 2024. 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 (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 (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 307 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 4,087 plaintiffs. 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 filed before Jan. 1, 2025, other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant 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%.
• 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 $305 million to $315 million.
• Property taxes are projected to be flat. This change is largely earnings neutral and is offset in revenue due to property tax trackers.
• Interest expense (net of AFUDC - debt) is projected to increase $140 million to $150 million, net of interest income.
• AFUDC - equity is projected to increase $65 million to $75 million.
• ETR is projected to be ~(6%) to (8%). The assumption change is largely due to an increase in the PTC rate, which is offset in revenue and is largely earnings neutral. The negative ETR is largely offset by PTCs flowing back to customers in 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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