• Second quarter GAAP diluted earnings per share were $0.52 in 2023 compared with $0.60 in 2022.
• Xcel Energy reaffirms 2023 EPS guidance of $3.30 to $3.40.

Xcel Energy Inc. (NASDAQ: XEL) today reported 2023 second quarter GAAP and ongoing earnings of $288 million, or $0.52 per share, compared with $328 million, or $0.60 per share in the same period in 2022.

Earnings reflect the impact of unfavorable weather, higher operating and maintenance (O&M) expenses and interest charges, without expected increases in regulatory recovery to offset these drivers including the outcome of the Minnesota Electric Rate Case.

“While second quarter earnings were lower than last year due to unfavorable weather and other drivers, we are taking actions to offset the impacts and are reaffirming our 2023 earnings guidance,” said Bob Frenzel, chairman, president and CEO of Xcel Energy.

“While we move forward with these actions, I’m proud of the progress we continue to make in leading the nation’s clean energy transition,” Frenzel said. “As we reported in our annual Corporate Sustainability Report, more than half of the electricity we provide to our customers comes from carbon-free resources. This quarter, we also broke ground on the Sherco solar project and the Colorado Power Pathway transmission project, which is already spurring unprecedented opportunities for new renewable energy and economic development on the Colorado Eastern Plains.”

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 July 27th through July 31st.

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 2023 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, 2022 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 work force 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; cyber security 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. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the three and six months ended June 30, 2023 and 2022, 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 diluted earnings were $0.52 per share in 2023, compared with $0.60 per share in 2022. The decrease was primarily driven by unfavorable weather experienced in Colorado and SPS territories as well as higher O&M and interest charges, without expected increases in regulatory recovery to offset these drivers including the outcome of the Minnesota Electric Rate Case. 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 — Earnings decreased $0.07 per share for the second quarter of 2023 and were flat year-to-date. Year-to-date earnings primarily reflect higher recovery of infrastructure investment (electric and natural gas), offset by increased depreciation, O&M expenses, interest charges and unfavorable weather.

NSP-Minnesota — Earnings increased $0.01 per share for the second quarter of 2023 and $0.03 year-to-date. The year-to-date change was driven by increased electric infrastructure investment (non-fuel riders).

SPS — Earnings decreased $0.02 per share for the second quarter of 2023 and year-to-date. The impact of regulatory rate outcomes and sales growth was more than offset by unfavorable weather, increased depreciation and interest expenses (excluding the impact of the prior year Texas rate case surcharge amounts).

NSP-Wisconsin — Earnings increased $0.02 per share for the second quarter of 2023 and year-to-date. Additional electric and natural gas infrastructure investment recoveries were partially offset by higher depreciation and O&M expenses.

Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company and earnings from Energy Impact Partners (EIP) funds equity method investments. Earnings decreased $0.01 per share for the second quarter and $0.04 year-to-date, largely attributable to higher interest charges.

Components significantly contributing to changes in 2023 EPS compared to 2022:

 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, decoupling mechanisms in Colorado and sales true-up mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather for the electric utility in those jurisdictions.

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 2023 compared to 2022:

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

• PSCo — Residential sales declined due to decreased use per customer, partially offset by a 1.3% increase in customers. The C&I sales decline was related to decreased use per customer, primarily due to the manufacturing and agricultural sectors.
• NSP-Minnesota — Residential sales declined due to decreased use per customer, partially offset by a 1.1% increase in customers.
• SPS — Residential sales growth was primarily attributable to a 0.8% increase in customers, partially offset by decreased use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
• NSP-Wisconsin — Residential sales declined due to decreased use per customer, offset by a 0.7% increase in customers. C&I sales growth was associated with customer growth, experienced largely in the transportation and professional services sectors.

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

• Natural gas sales reflect a lower use per residential customer in all jurisdictions, partially offset by an increase in C&I use per customer in PSCo. In addition, residential and C&I customer growth was 1.2% and 0.7%, respectively.

Electric Margin — Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.

Electric revenues, fuel and purchased power and margin:

Natural Gas Margin — Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.

Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.

Natural gas revenues, cost of natural gas sold and transported and margin:

O&M Expenses — O&M expenses increased $14 million for the second quarter and $62 million year-to-date. The increase was primarily due to timing of planned generation outages; additional bad debt expenses; higher insurance and the impact of inflationary pressures, including labor increases, partially offset by the recognition of previously deferred costs associated with the Texas Electric Rate Case in 2022 (approximately $16 million, offset in Electric revenues).

Depreciation and Amortization — Depreciation and amortization decreased $73 million for the second quarter and $11 million year-to-date, largely related to the recognition of previously deferred depreciation costs associated with the Texas Electric Rate Case in 2022 (approximately $40 million) and depreciation life extensions implemented in the Minnesota Electric Rate Case ($48 million), partially offset by system expansion.

Taxes (other than Income Taxes) — Taxes decreased $42 million for the second quarter and $29 million year-to-date, primarily associated with the $25 million of deferrals related to the Minnesota Electric Rate Case and the recognition of previously deferred costs associated with the Texas Electric Rate Case in 2022.

Other Income (Expense) — Other income (expense) increased $17 million for the second quarter and $21 million year-to-date, largely related to rabbi trust performance, which is partially offset in O&M expenses (employee benefit costs).

Interest Charges — Interest charges increased $21 million for the second quarter and $60 million year-to-date, largely due to higher interest rates and increased long-term debt levels, partially offset by the recognition of previously deferred costs associated with the Texas Electric Rate Case in 2022.

Income Taxes — Effective income tax rate:

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

Xcel Energy’s capital structure:

Liquidity — As of July 24, 2023, 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 assigned to Xcel Energy Inc. and its utility subsidiaries as of July 24, 2023:

2023 Financing Activity — During 2023, Xcel Energy plans to issue approximately $85 million of equity through the DRIP and benefit programs. In addition, we issued approximately $62 million of equity under the ATM program in the first half of 2023. Xcel Energy and its utility subsidiaries issued or plan to issue the following long-term debt:

Financing plans are subject to change, depending on regulatory outcomes, capital expenditures, the development of a tax credit transferability market, legislative initiatives, internal cash generation, market conditions and other factors.

Note 4. Rates, Regulation and Other

NSP-Minnesota — 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the Minnesota Public Utilities Commission (MPUC). The rate case is based on a requested ROE of 10.2%, a 52.5% equity ratio and forward test years. In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.

In March 2023, the ALJ’s report was issued, which included an estimated rate increase of approximately $386 million over three years from 2022-2024, based on a ROE of 9.87% and an equity ratio of 52.5%.

In July 2023, the MPUC approved a three-year rate increase of approximately $311 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. NSP-Minnesota plans to file for reconsideration of the decision in August 2023. The MPUC will have 60 days to respond to the reconsideration request.

Modifications to NSP-Minnesota’s request were as follows:

NSP-Minnesota — 2022 South Dakota Electric Rate Case — In June 2022, NSP-Minnesota filed a South Dakota electric rate case seeking a revenue increase of approximately $44 million. The filing was based on a 2021 historic test year adjusted for certain known and measurable changes, a requested return on equity of 10.75%, rate base of approximately $947 million and an equity ratio of 53%.

In June 2023, the South Dakota Public Utilities Commission (SDPUC) Staff approved an uncontested settlement agreement. Key terms of the decision include:

• Increase in base rate and infrastructure rider revenue of $14 million.
• Decreases in depreciation expense of $7 million (change in depreciable lives) and nuclear decommissioning expense of $5 million from NSP-Minnesota’s rate request.
• Confidential equity ratio and ROE.

NSP-Minnesota Solar Request for Proposal (RFP) — In May 2023, NSP-Minnesota filed a recommended portfolio, which proposed an additional 250 MW of self-build solar generation at the site of our retiring Sherco coal units and a 100 MW solar PPA located in Wisconsin as part of the resource plan RFP. A MPUC decision is expected later this year.

NSP-Wisconsin — Wisconsin Rate Case — In April 2023, NSP-Wisconsin filed a Wisconsin rate case seeking an electric increase of $40 million (rate increase of 4.8%) and a natural gas increase of $9 million (rate increase of 5.3%). The rate request is based on a ROE of 10.25%, a 52.5% equity ratio and 2024 forward-looking test year. A final decision by the Public Service Commission of Wisconsin is expected in late fourth quarter of 2023.

PSCo — Electric Rate Case — In November 2022, PSCo filed a Colorado electric rate case seeking a net increase of $262 million, or 8.2%. The total request reflects a $312 million increase (subsequently adjusted to $303 million in rebuttal), which includes $50 million of authorized costs currently recovered through various rider mechanisms. The request is based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of $11.3 billion.

PSCo’s request for a 2023 Transmission Cost Adjustment (TCA) rider revenue requirement of $41 million has also been consolidated with the pending electric rate case.

In June 2023, PSCo, the Staff, Utility Consumer Advocate, Colorado Energy Office, Colorado Energy Consumers and various other intervenors filed a nearly comprehensive settlement. The City of Boulder opposes the settlement. Terms of the settlement include:

• Retail revenue increase (excluding rider roll-ins) of $95 million (increase of 2.96%), based on a 2022 historic test year using year-end rate base with forward looking known and measurable adjustments.
• Alternatively, retail revenue increase (excluding rider roll-ins) of $47 million (increase of 1.46%), if depreciation expense deferrals associated with certain coal generating assets are accepted by the Colorado Public Utilities Commission (CPUC). This adjustment, if approved, would be earnings neutral, but reduce annual cash flow by $47 million.
• Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).
• Early termination of the revenue decoupling pilot with implementation of new rates.
• Continuation of previously authorized trackers and deferrals.
• Collection of $12 million of 2023 TCA revenues, previously suspended by the CPUC. Intervenors’ recommended adjustments to the TCA, including prudency tests, exclusion of repair or replacement projects and a historic test year, are subject to CPUC review and any changes to the TCA would apply prospectively beginning in 2024.

A CPUC decision is expected in the third quarter of 2023, with rates to be effective in September 2023.

SPS — 2022 New Mexico Electric Rate Case — In November 2022, Southwestern Public Service Company (SPS) filed a New Mexico electric rate case seeking a revenue increase of $78 million, or 10%. In May 2023, SPS revised its request to $75 million. The request is based on a ROE of 10.75%, an equity ratio of 54.7%, a future test year ending June 30, 2024, rate base of $2.4 billion and acceleration of the Tolk coal plant depreciation life from 2032 to 2028.

In May 2023, SPS, Staff, and various parties filed a contested comprehensive stipulation. Two environmental advocacy organizations opposed the stipulation. However, one intervenor withdrew their opposition and abstained. Hearings were held in June 2023. Terms of the contested stipulation include:

• Base rate revenue increase of $33 million, based on the filed future test year.
• ROE of 9.5%.
• Equity ratio of 54.7%.
• Acceleration of Tolk coal plant depreciation life to 2028.

A New Mexico Public Regulation Commission (NMPRC) decision is anticipated in the fourth quarter of 2023.

SPS — 2023 Texas Electric Rate Case — In February 2023, SPS filed a Texas electric rate case seeking an increase in base rate revenue of $149 million (13%). In March 2023, SPS updated the filing, which increased the rate revenue request to $158 million (14% impact to customer bills). The request is based on a ROE of 10.65%, an equity ratio of 54.6% and retail rate base of $3.6 billion. Additionally, the request reflects the acceleration of the Tolk coal plant depreciation life from 2034 to 2028. SPS is requesting a surcharge from July 13, 2023 through the effective date of new base rates.

Next steps in the procedural schedule are as follows:

• Intervenor direct testimony: August 4, 2023.
• Staff direct testimony: August 11, 2023.
• Rebuttal testimony: August 25, 2023.
• Hearings: Sept. 12-21, 2023.
• Proposed findings: Oct. 25, 2023.

A Public Utility Commission of Texas (PUCT) decision is expected in the first quarter of 2024.

SPS RFP — In July 2023, SPS filed a recommended portfolio, which includes 418 MW of self-build solar projects. A decision from PUCT and NMPRC is expected in 2024.

Note 5. 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.

As of July 24, 2023, PSCo is aware of approximately eight complaints on behalf of at least 586 plaintiffs relating to the Marshall Fire and expects that it may receive further complaints. 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, and inverse condemnation.

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. 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 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 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.

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 2023 Earnings Guidance — Xcel Energy’s 2023 GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per share.^(a)

Key assumptions as compared with 2022 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 relatively flat.
• Capital rider revenue is projected to increase $40 million to $50 million (net of PTCs). The change from the previous estimate is largely due to a change in the projected levels of PTCs driven by a change in the PTC rate, which are offset in the ETR and largely earnings neutral.
• O&M expenses are projected to decline ~3%.
• Depreciation expense is projected to increase approximately $30 million to $40 million. The change from the previous estimate is largely due to longer depreciation lives approved in the Minnesota Electric Rate Case and other regulatory decisions, which are generally offset by lower revenue.
• Property taxes are projected to decrease $20 million to $30 million. The change from the previous estimate is largely due to regulatory decisions, which are generally offset by lower revenue.
• Interest expense (net of AFUDC - debt) is projected to increase $80 million to $90 million. The change from the previous estimate is largely due to regulatory decisions (generally offset by lower revenue) and lower than projected interest rates on recent bond issuances.
• AFUDC - equity is projected to increase $0 million to $10 million.
• ETR is projected to be ~(9%) to (11%). The change from the previous estimate is largely due to a change in the projected levels of PTCs and a change in the PTC rate, which are offset in the capital riders and fuel mechanisms and are largely earnings neutral.

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 2022 base of $3.15 per share, which represents the mid-point of the original 2022 guidance range of $3.10 to $3.20 per share.
• Deliver annual dividend increases of 5% to 7%.
• Target a dividend payout ratio of 60% to 70%.
• Maintain senior secured debt credit ratings in the A range. 

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