Xcel Energy Inc. (NASDAQ: XEL) today reported 2021 GAAP and ongoing earnings of $1.60 billion, or $2.96 per share, compared with $1.47 billion, or $2.79 per share in the same period in 2020.

Earnings reflect higher electric and natural gas revenues, which were partially offset by increases in electric fuel and purchased power, costs of natural gas sold and transported, additional depreciation and lower allowance for funds used during construction (AFUDC).

“We had a solid year delivering earnings of $2.96 per share and achieving our earnings guidance for the 17th consecutive year. We are well positioned for the future and are reaffirming our 2022 ongoing EPS guidance of $3.10 - $3.20,” said Bob Frenzel, chairman, president and CEO.

“We also reached constructive regulatory settlements in Colorado with our clean energy plan, the Colorado Power Pathway transmission investment plan and our electric rate case. Additionally, we reached a settlement in principle in our Texas rate case.”

“Finally, I must extend my appreciation to the entire Xcel Energy team and our industry partners for their dedication and tireless work to help our Colorado customers impacted by the devastating wildfires and historic windstorm in December. It is inspiring to see how the entire community came together to support one another, and I am thankful for our employees and all those who have played a role in helping those who have lost so much.”

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 12:00 p.m. CDT on Jan. 27 through 12:00 p.m. CDT on Jan. 30.

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 the 2022 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, 2020 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: uncertainty around the impacts and duration of the COVID-19 pandemic; operational safety, including our nuclear generation facilities; 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; ability to recover costs, changes in regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including 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; 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; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.

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 twelve months ended Dec. 31, 2021 and 2020, 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 2021 earnings were $2.96 per share compared to $2.79 per share in 2020. The increase was driven by capital investment recovery and other regulatory outcomes, partially offset by increases in depreciation and lower AFUDC. 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 revenues are offset by the related variation in costs).

Summarized diluted EPS for Xcel Energy:

^(a) Amounts may not add due to rounding.

PSCo — Earnings increased $0.11 per share for 2021, driven by capital investment recovery and other regulatory outcomes. Higher revenues were partially offset by increased depreciation, operating and maintenance (O&M) expenses and other taxes (other than income taxes).

NSP-Minnesota — Earnings were flat for 2021 compared to 2020, reflecting capital investment recovery offset by additional depreciation and interest charges.

SPS — Earnings increased $0.03 per share for 2021, largely related to capital investment recovery and other regulatory outcomes, lower income tax, O&M and interest expenses, partially offset by decreased AFUDC.

NSP-Wisconsin — Earnings were flat for 2021 compared to 2020.

Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company, offset by earnings from Energy Impact Partners (EIP) investments.

Components significantly contributing to changes in 2021 EPS compared with 2020:

ROE for Xcel Energy and its utility subsidiaries:

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

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 2021 compared to 2020:

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

Weather-adjusted sales results for each of our utility subsidiaries in 2021 reflect improving economies as the adverse effects of COVID-19 lessen. The recovery reflects increased sales in the C&I sector as businesses return to a more normal level. Residential sales remain elevated from pre-pandemic levels due to continuance of individuals working from home.

• PSCo — Residential sales rose based on a 1.2% increase in customers, combined with higher use per customer. The growth in C&I sales was due to a 1.2% increase in customers, partially offset by slightly lower use per customer, primarily in the services sector.

• NSP-Minnesota — Residential sales growth reflects a 1.2% increase in customers, partially offset by a lower use per customer. The growth in C&I sales was due to a 0.9% increase in customers and higher use per customer, primarily in the manufacturing, retail and services sectors.

• SPS — Residential sales declined as lower use per customer offset a 0.9% increase in customers. C&I sales increased due to a 0.5% increase in customers and higher use per customer, primarily driven by the oil and gas and professional services sectors.

• NSP-Wisconsin — Residential sales growth was attributable to a 0.8% increase in customer additions, partially offset by slightly lower use per customer. The growth in C&I sales was due to a 1.1% increase in customers, primarily led by increases in the manufacturing, health care and retail trade sectors.

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

• Natural gas sales primarily reflect a 1.2% increase in residential customers and a 0.5% increase in C&I customers, partially offset by a decrease in use per customer.

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 impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes. See Note 5 for discussion of Winter Storm Uri.

Electric revenues, fuel and purchased power and margin:

Change in electric 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. See Note 5 for discussion of Winter Storm Uri.

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

Change in natural gas margin:

O&M Expenses — O&M expenses decreased $3 million year-to-date. Increases for distribution, wind farm maintenance and technology costs were offset by a decrease in employee benefits expense (e.g., long-term incentives), additional Texas 2021 rate case deferrals and the year-over-year impact of amounts associated with the Texas 2019 rate case surcharge.

Depreciation and Amortization — Depreciation and amortization increased $173 million year-to-date. The increase was primarily driven by several wind farms going into service, normal system expansion and the implementation of new depreciation rates in various states.

Other Income (Expense) — Other income (expense) increased $11 million year-to-date. The change was largely related to gains associated with rabbi trust performance (offset in O&M expenses).

AFUDC, Equity and Debt — AFUDC decreased $58 million year-to-date. The decrease was driven by completion of various wind projects throughout 2020 and 2021.

Interest Charges — Interest charges increased $2 million year-to-date. The increase was largely due to higher debt levels to fund capital investments, partially offset by lower long-term and short-term interest rates.

Earnings from Equity Method Investments — Earnings from equity method investments increased $22 million year-to-date. The year-to-date change was largely attributable to the performance of the EIP funds, which invest in energy technology companies.

Income Taxes — Effective income tax rate:

Income tax benefit increased $64 million year-to-date. The change was driven by an increase in wind PTCs due to additional wind facilities going into service. Impact of PTCs was partially offset by an increase in pretax earnings, lower plant regulatory differences and lower non-plant accumulated deferred income tax amortization.

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

Xcel Energy’s capital structure:

Liquidity — As of Jan. 24, 2022, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

Term Loan Agreements — In the fourth quarter of 2021, Xcel Energy paid off a $1.2 billion 364-Day Term Loan Agreement that was entered in February 2021 to enhance liquidity due to the incremental fuel costs from Winter Storm Uri and regulatory lag in recovery.

Bilateral Credit Agreement — In April 2021, NSP-Minnesota extended an uncommitted bilateral credit agreement of $75 million (which is limited in use to support letters of credit for one-year). NSP-Minnesota had $45 million of outstanding letters of credits as of Dec. 31, 2021.

ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an at-the-market offering (ATM) program. As of Dec. 31, 2021, Xcel Energy issued 5.33 million shares of common stock with net proceeds of $346.5 million through the ATM program.

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 Jan. 24, 2022:

2021 Financing Activity — During 2021, Xcel Energy issued approximately $74 million of equity through the Dividend Reinvestment Program and other benefit programs. In addition, Xcel Energy Inc. and its utility subsidiaries issued the following bonds:

2022 Planned Financing Activities — During 2022, Xcel Energy Inc. and its utility subsidiaries anticipate the following:

• Xcel Energy Inc. — approximately $600 million in unsecured bonds during Q2.

• PSCo — approximately $650 million of first mortgage bonds during Q2.

• SPS — approximately $150 million of first mortgage bonds during Q2.

• NSP-Minnesota — approximately $500 million of first mortgage bonds during Q2.

• NSP-Wisconsin — approximately $100 million of first mortgage bonds during Q3.

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 and Regulation

NSP-Minnesota — 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested ROE of 10.2%, a 52.50% equity ratio and forward test years. The request is detailed as follows:

In addition, NSP-Minnesota requested interim rates, subject to refund, of $288 million to be implemented in January 2022 and an incremental $135 million to be implemented in January 2023. In December 2021, the MPUC approved rates of $247 million to begin on Jan. 1, 2022. The adjusted level reflects exigent circumstances from the COVID-19 pandemic. The next steps in the procedural schedule are expected to be as follows:

• Intervenor testimony: Oct. 3, 2022

• Rebuttal testimony: Nov. 8, 2022

• Public hearing: Dec. 13-16, 2022

• Administrative Law Judge (ALJ) Report: March 31, 2023

• MPUC Order: June 30, 2023

NSP-Minnesota — 2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested return on equity of 10.5%, rate base of $934 million and an equity ratio of 52.50%. In December 2021, the MPUC approved the requested interim rates of $25 million, subject to refund, beginning on Jan. 1, 2022. The next steps in the procedural schedule are expected to be as follows:

• Intervenor testimony: Aug. 30, 2022

• Rebuttal testimony: Oct. 4, 2022

• Public hearing: Nov. 1-4, 2022

• ALJ Report: Feb. 6, 2023

• MPUC Order: April 26, 2023

NSP-Minnesota — 2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) for a natural gas rate increase of $7 million, or 10.49%. The filing is based on a requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and a rate base of approximately $140 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021. A NDPSC decision is expected in early fall 2022. The next steps in the procedural schedule are expected to be as follows:

• Intervenor testimony: March 1, 2022

• Rebuttal testimony: April 1, 2022

• Hearings: June 1-3, 2022

NSP-Wisconsin — Wisconsin Electric and Natural Gas Settlement — In December 2021, the PSCW approved a rate case settlement agreement and 2022 fuel cost plan without modification. New rates and tariffs were effective Jan. 1, 2022. Key elements of the settlement:

• An increase in electric rates of $35 million (4.9%) for 2022 and an incremental $18 million increase (2.5%) for 2023.

• An increase in natural gas rates of $10 million (8.4%) for 2022 and an incremental $3 million (2.3%) for 2023.

• ROE of 9.80% for 2022 and 10.00% for 2023.

• Equity ratio of 52.5% for both 2022 and 2023.

• Returning $9 million in various net regulatory liabilities to offset customer impacts in 2023.

• Deferring certain pension and other post-employment benefit expense in 2021 through 2023.

• Incorporating an earnings sharing mechanism for 2022 and 2023.

NSP-Wisconsin — Michigan Electric Rate Case — In January 2022, NSP-Wisconsin reached an electric rate case settlement in principle with the Michigan Public Service Commission (MPSC) staff and others. The settlement grants NSP-Wisconsin an electric revenue increase of $1.6 million in 2022, based on a ROE of 9.7% and an equity ratio of 52.5%. The MPSC is expected to rule on the settlement in the first quarter of 2022.

PSCo — Colorado Electric Rate Request — In July 2021, PSCo filed a request with the Colorado Public Utilities Commission (CPUC) seeking a net electric rate increase of $343 million (or 12.4%). The total request reflects a $470 million increase, which includes $127 million of previously authorized costs currently recovered through various rider mechanisms. The request was based on a 10.0% ROE, an equity ratio of 55.64%, a 2022 forecast test year, a rate base of $10.3 billion and impacts of a new depreciation study.

In January 2022, PSCo reached an unopposed comprehensive settlement. The CPUC is expected to rule on the settlement in March 2022 with final rates expected to be effective in April 2022. Key settlement terms include:

• A net electric rate increase of $177 million. The total change in base rates is $299 million, which includes $122 million of revenue previously collected through various rider mechanisms.

• A ROE of 9.3% and an equity ratio of 55.69%.

• A current 2021 test year (average rate base) with the transfer of Cheyenne Ridge, Wildfire Mitigation Plan and Advanced Grid Intelligence and Security (AGIS) investments at year-end rate base.

• Approval of all of PSCo’s proposed depreciation adjustments.

• Continuation of the property tax, qualified pension, and non-qualified pension trackers.

• Continuation of AGIS deferral including interest equivalent to PSCo's weighted average cost of capital once the balance exceeds $50 million.

• Continuation of the Wildfire Mitigation Plan deferral, with a debt return.

PSCo — Resource Plan Settlement — In November 2021, PSCo and multiple intervenors filed a partial settlement of the resource plan, which will result in an expected 87% carbon reduction and an 80% renewable mix by 2030. A CPUC decision is expected in the first quarter of 2022. Key settlement terms include:

• Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in 2028 (was 2030).

• Conversion of Pawnee to burn natural gas by 2026.

• Early retirement of Comanche 3 in 2034 with reduced operations beginning in 2025.

• Addition of ~2,300 MW of wind.

• Addition of ~1,600 MW of universal-scale solar.

• Addition of 400 MW of storage.

• Addition of 1,300 MW of flexible, dispatchable generation.

• Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.

PSCo — Pathway Transmission Expansion Settlement — In November 2021, PSCo filed a non-unanimous settlement agreement with Staff and several other parties regarding its CPCN request for the Pathway Transmission project. Key settlement terms include:

• The parties agreed that PSCo met the burden of proof demonstrating that the project was needed to facilitate the renewables in the Integrated Resource Plan (IRP) and is in the public interest.

• Agreed to a cost estimate of $1.7 billion and recovery through the transmission rider.

• The Pathway project will also include a Performance Incentive Mechanism such that applicable costs in a given year above or below a 5% dead band would allow for a ROE penalty or adder.

• Parties agreed to conditional CPCN approval for 345 kV extension project subject to the project being included in the final approved IRP plan with a cost estimate of $247 million.

PSCo — Natural Gas Rate Case — On Jan. 24, 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the Pipeline System Integrity Adjustment (PSIA) rider, which was closed to new investments at the end of 2021. The request is based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year. PSCo has requested a proposed effective date of Nov. 1, 2022.

Additionally, PSCo’s request includes step revenue increases of $40 million in 2023 (effective Nov. 1, 2023) and $41 million in 2024 (effective Nov. 1, 2024) related to continued capital investment. Under this proposal, PSCo would not request another base rate change prior to Nov. 1, 2025. An informational historical test year including a 10.75% ROE was also filed as required by the CPUC.

The request supports fundamental infrastructure investments to serve customers, consistent with PSCo’s obligation to provide safe, reliable service while enabling PSCo to continue to be a leader of the clean energy transition in partnership with the CPUC to achieve clean heat goals.

^(a) Includes approximately $28 million as a result of the increase in ROE from 9.2% to 10.25%.

SPS — New Mexico 2021 Electric Rate Case — In January 2021, SPS filed an electric rate case with the New Mexico Public Regulation Commission (NMPRC) with a current requested base rate increase of approximately $84 million.

In June 2021, SPS and various parties filed an uncontested stipulation with the NMPRC, which reflected a $62 million rate increase, a change in the depreciation life of the Tolk coal plant to 2032, an equity ratio of 54.72% and ROE of 9.35% for reconciliation statements and determining the revenue requirements for the Sagamore and Hale wind projects. In December 2021, the Hearing Examiner issued a recommendation that the NMPRC approve the rate case settlement agreement without modification. A NMPRC decision and implementation of final rates is anticipated in the first quarter of 2022.

SPS — Texas 2021 Electric Rate Case — In February 2021, SPS filed an electric rate case with the Public Utilities Commission of Texas (PUCT) and its municipalities, seeking an increase in base rates of approximately $140 million. SPS’ net rate increase to Texas customers is expected to be approximately $71 million, or 9.2%, as a result of the offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.

The request is based on a ROE of 10.35%, an equity ratio of 54.60%, a rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020. The request includes the effect of losing approximately 400 MW from a wholesale transmission customer and changes to depreciation lives of SPS’ Tolk power plant (from 2037 to 2032) and coal handling assets at the Harrington facility (to 2024).

On Jan. 26, 2022, SPS and intervenors filed a blackbox settlement. Key terms include:

• A base rate increase of approximately $89 million effective back to March 15, 2021.

• A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only.

• The depreciation lives for Tolk moved up to 2034 and Harrington coal assets moved up to 2024.

A PUCT decision is expected in the first quarter of 2022.

Note 5. Winter Storm Uri

In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $1 billion (largely deferred as regulatory assets).

Regulatory Overview — Xcel Energy has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, the utility subsidiaries have deferred February cost increases for future recovery and sought recovery of the cost increases over a period of up to 63 months to mitigate the impact to customer bills. Additionally, we did not request recovery of financing costs in order to further limit the impact to our customers.

Proceedings initiated:

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

Xcel Energy 2022 Earnings Guidance — Xcel Energy’s 2022 GAAP and ongoing earnings guidance is a range of $3.10 to $3.20 per share.^(a)

Key assumptions as compared with 2021 levels unless noted:

• Constructive outcomes in all rate case and regulatory proceedings.

• Normal weather patterns for the year.

• Weather-normalized retail electric sales are projected to increase ~1%.

• Weather-normalized retail firm natural gas sales are projected to be 0% to 1%.

• Capital rider revenue is projected to increase $35 million to $45 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to other regulatory mechanisms.

• O&M expenses are projected to increase approximately 1% to 2%.

• Depreciation expense is projected to increase approximately $255 million to $265 million.

• Property taxes are projected to increase approximately $40 million to $50 million.

• Interest expense (net of AFUDC - debt) is projected to increase $55 million to $65 million.

• AFUDC - equity is projected to be relatively flat.

• ETR is projected to be ~(3%) to (5%). The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.

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 2021 base of $2.96 per share, which represents the mid-point of the revised 2021 guidance range of $2.94 to $2.98 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.

View source version on businesswire.com: https://www.businesswire.com/news/home/20220127005160/en/

Paul Johnson, Vice President - Treasurer & Investor Relations, (612) 215-4535

For news media inquiries only, please call Xcel Energy Media Relations, (612) 215-5300 

Xcel Energy website address: www.xcelenergy.com