Document

EX-99.01 2 xcelearningsreleaseq32023.htm EX-99.01 Document

Exhibit 99.01


			414 Nicollet Mall
10/27/23			Minneapolis, MN 55401

XCEL ENERGY

THIRD QUARTER 2023 EARNINGS REPORT

•Third quarter GAAP diluted earnings per share were $1.19 in 2023 compared with $1.18 in 2022.

•Third quarter diluted ongoing earnings per share were $1.23 in 2023 compared with $1.18 in 2022.

•Year-to-date GAAP diluted earnings per share for 2023 were $2.47 compared to $2.48 in 2022.

•Year-to-date diluted ongoing earnings per share for 2023 were $2.52 compared to $2.48 in 2022.

•Xcel Energy narrows its 2023 ongoing EPS guidance to $3.32 to $3.37 from $3.30 to $3.40 per share.

•Xcel Energy initiates 2024 EPS guidance of $3.50 to $3.60 per share.

MINNEAPOLIS — Xcel Energy Inc. (NASDAQ: XEL) today reported 2023 third quarter GAAP earnings of $656 million, or $1.19 per share, compared with $649 million, or $1.18 per share in the same period in 2022 and ongoing earnings of $682 million, or $1.23 per share, compared with $649 million, or $1.18 per share in the same period in 2022. See Note 7 for reconciliation from GAAP to ongoing earnings.

Third quarter ongoing earnings results reflect the impact of increased recovery of infrastructure investments, higher sales and demand, lower operating and maintenance (O&M) expenses, partially offset by increased interest charges and depreciation.

“Xcel Energy delivered solid performance during the third quarter,” said Bob Frenzel, chairman, president and CEO of Xcel Energy. “As a result, we are narrowing our 2023 ongoing earnings guidance to $3.32 to $3.37 per share and initiating 2024 guidance of $3.50 to $3.60 per share.”

“We made significant progress on our industry-leading clean energy transition plans. In September, we filed a proposed plan for the largest clean energy transition effort in Colorado history. The plan includes approximately 6,500 MW of renewable energy and battery storage, and approximately 600 MW of natural gas resources to ensure reliability. With the benefits of the Inflation Reduction Act, the resources in the plan would have an annual rate impact of approximately 2.3%.”

“In addition, in October the U.S. Department of Energy selected the Heartland Hydrogen Hub, including multiple clean hydrogen projects from Xcel Energy, to receive up to $925 million in federal funding. The award will serve as a catalyst for a future hydrogen ecosystem in the Upper Midwest,” said Frenzel. “The future is bright for Xcel Energy, our communities, customers and investors.”

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.


US Dial-In:			1 (866) 580-3963
International Dial-In:			(400) 120-0558
Conference ID:			2633836

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 Oct. 27th through Oct. 30th.


Replay Numbers
US Dial-In:			1 (866) 583-1035
Access Code:			2633836#

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 and 2024 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 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.

For more information, contact:


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

Roopesh Aggarwal, Senior Director - Investor Relations		(303) 571-2855

Xcel Energy website address:	www.xcelenergy.com	(612) 215-5300

This information is not given in connection with any

sale, offer for sale or offer to buy any security.

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in millions, except per share data)


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
	2023		2022		2023		2022
Operating revenues
Electric	$	3,387	$	3,699	$	8,751	$	9,255
Natural gas	245		357		1,926		1,923
Other	30		26		87		79
Total operating revenues	3,662		4,082		10,764		11,257

Operating expenses
Electric fuel and purchased power	1,181		1,497		3,328		3,772
Cost of natural gas sold and transported	70		173		1,084		1,134
Cost of sales — other	14		11		37		32
Operating and maintenance expenses	586		611		1,864		1,827
Conservation and demand side management expenses	76		86		215		259
Depreciation and amortization	618		607		1,807		1,807
Taxes (other than income taxes)	168		173		489		523
Loss on Comanche Unit 3 litigation	34		—		34		—
Total operating expenses	2,747		3,158		8,858		9,354

Operating income	915		924		1,906		1,903

Other income (expense), net	3		(15)		19		(20)
Earnings from equity method investments	7		1		27		27
Allowance for funds used during construction — equity	26		20		63		53

Interest charges and financing costs
Interest charges — includes other financing costs of $8, $8, $16 and $16, respectively	269		244		790		705
Allowance for funds used during construction — debt	(14)		(7)		(36)		(19)
Total interest charges and financing costs	255		237		754		686

Income before income taxes	696		693		1,261		1,277
Income tax expense (benefit)	40		44		(101)		(80)
Net income	$	656	$	649	$	1,362	$	1,357

Weighted average common shares outstanding:
Basic	552		548		551		546
Diluted	552		548		552		546

Earnings per average common share:
Basic	$	1.19	$	1.19	$	2.47	$	2.48
Diluted	1.19		1.18		2.47		2.48

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.

Note 1. Earnings Per Share Summary

Xcel Energy’s third quarter GAAP diluted earnings were $1.19 per share, compared with $1.18 per share in the same period in 2022 and ongoing diluted earnings were $1.23 per share in 2023, compared with $1.18 per share in 2022. The increase in ongoing earnings per share was primarily driven by increased recovery of infrastructure investments, higher sales and demand and lower O&M expenses, partially offset by increased interest charges and depreciation. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

Summarized diluted EPS for Xcel Energy:


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share	2023		2022		2023		2022
PSCo	$	0.41	$	0.45	$	0.97	$	1.02
NSP-Minnesota	0.47		0.49		0.95		0.94
SPS	0.30		0.25		0.55		0.52
NSP-Wisconsin	0.06		0.07		0.18		0.19
Earnings from equity method investments — WYCO	0.01		0.01		0.03		0.02
Regulated utility (a)	1.25		1.28		2.68		2.69
Xcel Energy Inc. and Other	(0.06)		(0.09)		(0.22)		(0.21)
GAAP diluted EPS (a)	1.19		1.18		2.47		2.48
Loss on Comanche Unit 3 litigation (b)	0.05		—		0.05		—
Ongoing diluted EPS (a)	$	1.23	$	1.18	$	2.52	$	2.48

(a)Amounts may not add due to rounding.

(b)See Note 7.

PSCo — GAAP diluted earnings decreased $0.04 per share and ongoing diluted earnings increased $0.01 per share for the third quarter. Year-to-date GAAP diluted earnings decreased $0.05 per share and ongoing diluted earnings were flat. Year-to-date ongoing earnings primarily reflect higher recovery of infrastructure investment (electric and natural gas), which were offset by increased depreciation and interest charges. See Note 7 for reconciliation from GAAP to ongoing earnings.

NSP-Minnesota — GAAP and ongoing earnings decreased $0.02 per share for the third quarter of 2023 and increased $0.01 per share year-to-date. The year-to-date change was driven by increased recovery of electric infrastructure investments, partially offset by higher O&M expenses, interest charges and unfavorable weather.

SPS — GAAP and ongoing earnings increased $0.05 per share for the third quarter of 2023 and $0.03 year-to-date. The impact of regulatory rate outcomes and sales growth was partially offset by unfavorable weather, increased depreciation and interest expenses.

NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 per share for the third quarter of 2023 and year-to-date. Additional electric and natural gas infrastructure investment recoveries were offset by higher depreciation, O&M expenses and interest expenses.

Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from Energy Impact Partners (EIP) funds equity method investments. Year-to-date fluctuations are largely attributable to increased interest rates.

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


Diluted Earnings (Loss) Per Share	Three Months Ended Sept. 30		Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS — 2022	$	1.18	$	2.48

Components of change - 2023 vs. 2022
(Lower) higher natural gas revenues, net of cost of natural gas sold and transported	(0.01)		0.07
Lower conservation and demand side management expenses (offset in electric revenues)	0.02		0.06
Higher other income (expense)	0.02		0.05
Lower taxes (other than income taxes)	0.01		0.05
Lower effective tax rate (ETR) (a)	0.01		0.03
Higher depreciation and amortization	(0.02)		—
Higher interest charges	(0.03)		(0.11)
Higher (lower) electric revenues, net of electric fuel and purchased power	0.01		(0.08)
Lower (higher) O&M expenses	0.03		(0.05)
Loss on Comanche Unit 3 litigation	(0.05)		(0.05)
Other, net	0.02		0.02
GAAP diluted EPS — 2023	1.19		2.47
Loss on Comanche Unit 3 litigation (See Note 7)	0.05		0.05
Ongoing diluted EPS — 2023 (b)	$	1.23	$	2.52

(a)Includes production tax credits (PTCs) and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.

(b)Amounts may not add due to rounding.

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 (mechanism expired in September 2023) 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:


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2023 vs. Normal		2022 vs. Normal		2023 vs. 2022		2023 vs. Normal		2022 vs. Normal		2023 vs. 2022
Retail electric	$	0.032	$	0.074	$	(0.042)	$	0.035	$	0.123	$	(0.088)
Decoupling and sales true-up	0.007		(0.032)		0.039		(0.015)		(0.055)		0.040
Electric total	$	0.039	$	0.042	$	(0.003)	$	0.020	$	0.068	$	(0.048)
Firm natural gas	(0.002)		—		(0.002)		0.024		0.019		0.005
Decoupling	$	0.001	$	—	$	0.001	$	0.001	$	—	$	0.001
Gas total	$	(0.001)	$	—	$	(0.001)	$	0.025	$	0.019	$	0.006
Total	$	0.038	$	0.042	$	(0.004)	$	0.045	$	0.087	$	(0.042)

Sales — Sales growth (decline) for actual and weather-normalized sales in 2023 compared to 2022:


	Three Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(5.9)	%	0.7	%	3.6	%	0.3	%	(1.4)	%
Electric C&I	(2.0)		(1.6)		6.5		(2.3)		0.5
Total retail electric sales	(3.4)		(0.8)		5.7		(1.6)		(0.1)
Firm natural gas sales	1.3		—		N/A		(3.2)		0.6


	Three Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	5.6	%	2.6	%	1.8	%	0.4	%	3.4	%
Electric C&I	1.7		(1.8)		6.0		(2.5)		1.3
Total retail electric sales	3.0		(0.4)		4.9		(1.7)		1.9
Firm natural gas sales	2.4		3.0		N/A		0.3		2.5


	Nine Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(4.4)	%	(0.1)	%	(3.3)	%	(2.6)	%	(2.4)	%
Electric C&I	(2.1)		(0.7)		5.5		(0.3)		0.7
Total retail electric sales	(2.9)		(0.5)		3.8		(1.0)		(0.2)
Firm natural gas sales	4.9		(10.7)		N/A		(12.7)		(1.6)


	Nine Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	1.4	%	0.6	%	0.9	%	(0.5)	%	0.8	%
Electric C&I	(0.2)		(0.9)		5.7		(0.2)		1.2
Total retail electric sales	0.3		(0.4)		4.7		(0.3)		1.1
Firm natural gas sales	1.6		(1.4)		N/A		(1.9)		0.4

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

•PSCo — Residential sales increased due to a 1.3% increase in customers. The C&I sales decline was related to decreased use per customer, primarily in the manufacturing and agricultural sectors.

•NSP-Minnesota — Residential sales increased due to a 1.1% increase in customers, partially offset by a decreased use per customer. C&I sales declined due to decreased use per customer, due to general economic conditions.

•SPS — Residential sales growth was primarily attributable to a 0.7% increase in customers and increased 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 decline was associated with decreased use per customer, experienced largely in the manufacturing sector.

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:


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Millions of Dollars)	2023		2022		2023		2022
Electric revenues	$	3,387	$	3,699	$	8,751	$	9,255
Electric fuel and purchased power	(1,181)		(1,497)		(3,328)		(3,772)
Electric margin	$	2,206	$	2,202	$	5,423	$	5,483


(Millions of Dollars)	Three Months Ended Sept. 30, 2023 vs. 2022		Nine Months Ended Sept. 30, 2023 vs. 2022
Revenue recognition for the Texas rate case surcharge (a)	$	—	$	(85)
Conservation and demand side management (offset in expense)	(14)		(48)
Estimated impact of weather (net of decoupling/sales true-up)	(2)		(34)
PTCs flowed back to customers (offset by lower ETR)	(10)		(33)
Non-fuel riders	39		70
Sales and demand (b)	18		38
Wholesale transmission (net)	(8)		15
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico, Wisconsin, South Dakota and Michigan)	1		13

Other (net)	(20)		4



Total increase (decrease)	$	4	$	(60)

(a)The decline in electric margin is due to the recognition of the Texas rate case outcome in the second quarter of 2022, which was largely offset by recognition of previously deferred costs.

(b)Sales excludes weather impact, net of partial decoupling in Colorado (mechanism expired in September) and sales true-up mechanism in Minnesota.

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:


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Millions of Dollars)	2023		2022		2023		2022
Natural gas revenues	$	245	$	357	$	1,926	$	1,923
Cost of natural gas sold and transported	(70)		(173)		(1,084)		(1,134)
Natural gas margin	$	175	$	184	$	842	$	789


(Millions of Dollars)	Three Months Ended Sept. 30, 2023 vs. 2022		Nine Months Ended Sept. 30, 2023 vs. 2022
Regulatory rate outcomes (Colorado and Wisconsin)	$	—	$	49
Estimated impact of weather (net of decoupling)	—		5





Other (net)	(9)		(1)
Total (decrease) increase	$	(9)	$	53

O&M Expenses — O&M expenses decreased $25 million for the third quarter and increased $37 million year-to-date. The year-to-date increase was primarily due to higher bad debt expenses; the impact of inflationary pressures, including labor increases and insurance, and unplanned maintenance at generating plants, offset by the change in deferred costs associated with the Texas Electric Rate Cases (offset in electric revenues) and impact of management cost containment actions.

Depreciation and Amortization — Depreciation and amortization increased $11 million for the third quarter and was flat year-to-date. Year-to-date activity is related to system expansion, offset by 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.

Taxes (other than Income Taxes) — Taxes decreased $5 million for the third quarter and $34 million year-to-date, primarily due to deferrals related to the Minnesota Electric Rate Case and the recognition of previously deferred costs associated with the Texas Electric Rate Case in 2022, partially offset by an increase in Colorado property tax expense.

Other Income (Expense) — Other income (expense) increased $18 million for the third quarter and $39 million year-to-date, largely related to interest earned on cash balances and rabbi trust performance, which is partially offset in O&M expenses (employee benefit costs).

Interest Charges — Interest charges increased $25 million for the third quarter and $85 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:


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2023		2022		2023 vs. 2022		2023		2022		2023 vs. 2022
Federal statutory rate	21.0	%	21.0	%	—	%	21.0	%	21.0	%	—	%
State tax (net of federal tax effect)	5.0		4.9		0.1		4.9		4.9		—
(Decreases) increases:
Wind PTCs (a)	(13.8)		(12.3)		(1.5)		(27.3)		(25.2)		(2.1)
Plant regulatory differences (b)	(5.3)		(5.8)		0.5		(5.5)		(5.5)		—

Other tax credits, net operating loss & tax credits allowances	(1.1)		(1.2)		0.1		(1.2)		(1.4)		0.2
Other (net)	(0.1)		(0.3)		0.2		0.1		(0.1)		0.2
Effective income tax rate	5.7	%	6.3	%	(0.6)	%	(8.0)	%	(6.3)	%	(1.7)	%

(a)Wind PTCs are credited to customers (reduction to revenue) and do not materially impact earnings.

(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

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

Xcel Energy’s capital structure:


(Millions of Dollars)	Sept. 30, 2023		Percentage of Total Capitalization		Dec. 31, 2022		Percentage of Total Capitalization
Current portion of long-term debt	$	1,051	2	%	$	1,151	3	%
Short-term debt	—		—		813		2
Long-term debt	24,910		58		22,813		55
Total debt	25,961		60		24,777		60
Common equity	17,309		40		16,675		40
Total capitalization	$	43,270	100	%	$	41,452	100	%

Liquidity — As of Oct. 23, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity
Xcel Energy Inc.	$	1,500	$	—	$	1,500	$	19	$	1,519
PSCo	700		239		461		3		464
NSP-Minnesota	700		15		685		8		693
SPS	500		—		500		18		518
NSP-Wisconsin	150		—		150		8		158
Total	$	3,550	$	254	$	3,296	$	56	$	3,352

(a) Expires September 2027.

(b) Includes outstanding commercial paper and letters of credit.

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 Oct. 23, 2023:

Credit Type

Company

Moody’s

S&P Global Ratings

Fitch

Senior unsecured debt

Xcel Energy Inc.

Baa1

BBB+

Senior secured debt

NSP-Minnesota

Aa3

A+

NSP-Wisconsin

Aa3

A+

PSCo

A+

SPS

A-

Commercial paper

Xcel Energy Inc.

P-2

A-2

NSP-Minnesota

P-1

A-1

NSP-Wisconsin

P-1

A-2

PSCo

P-2

A-2

SPS

P-2

A-2

Capital Expenditures — Base capital expenditures and incremental capital forecasts for Xcel Energy for 2024 through 2028:


	Base Capital Forecast (Millions of Dollars)
By Regulated Utility	2024		2025		2026		2027		2028		Total
PSCo	$	2,580	$	2,940	$	3,030	$	3,070	$	2,640	$	14,260
NSP-Minnesota	2,660		2,970		2,380		2,500		2,180		12,690
SPS	910		780		660		870		830		4,050
NSP-Wisconsin	570		600		570		600		650		2,990
Other (a)	(20)		—		10		10		10		10
Total base capital expenditures	$	6,700	$	7,290	$	6,650	$	7,050	$	6,310	$	34,000

(a) Other category includes intercompany transfers for safe harbor wind turbines.


	Base Capital Forecast (Millions of Dollars)
By Function	2024		2025		2026		2027		2028		Total
Electric transmission	$	1,880	$	2,150	$	2,500	$	2,840	$	2,080	$	11,450
Electric distribution	1,720		1,840		2,030		2,200		2,410		10,200
Electric generation	930		1,160		780		740		600		4,210
Natural gas	740		680		630		620		570		3,240
Renewables	670		740		40		20		20		1,490
Other	760		720		670		630		630		3,410
Total base capital expenditures	$	6,700	$	7,290	$	6,650	$	7,050	$	6,310	$	34,000

The base plan does not include any potential renewable generation assets associated with the Colorado recommended Preferred Plan (pending CPUC approval) and potential renewable generation additions at the NSP System and SPS, which could result in additional capital expenditures of approximately $10 billion. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt.

Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.

Financing for Capital Expenditures through 2028 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Current estimated financing plans of Xcel Energy for 2024 through 2028 (includes the impact of tax credit transferability):


(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)	$	20,520
New debt (b)	10,980
Equity through the Dividend Reinvestment and Stock Purchase Program (DRIP) and benefit program	500
Other equity	2,000
Base capital expenditures 2024-2028	$	34,000

Maturing debt	$	3,780

(a) Net of dividends and pension funding.

(b) Reflects a combination of short and long-term debt; net of refinancing.

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 nine months of 2023. Xcel Energy and its utility subsidiaries issued the following long-term debt:

Issuer

Security

Amount (in millions)

Status

Tenor

Coupon

Xcel Energy

Unsecured Senior Notes

800

Completed

10 Year

5.45

PSCo

First Mortgage Bonds

850

Completed

30 Year

5.25

NSP-Minnesota

First Mortgage Bonds

800

Completed

30 Year

5.10

NSP-Wisconsin

First Mortgage Bonds

125

Completed

30 Year

5.30

SPS

First Mortgage Bonds

100

Completed

30 Year

6.00

Financing plans are subject to change, depending on regulatory outcomes, capital expenditures, 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 request was based on a 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 July 2023, the MPUC approved a three-year rate increase of approximately $316 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.

In October 2023, the MPUC denied NSP-Minnesota’s request for reconsideration of certain aspects of the decision. NSP-Minnesota plans to file an appeal of the decision to the Minnesota Court of Appeals in November 2023.

NSP-Minnesota — 2024 Minnesota Natural Gas Rate Case — NSP-Minnesota plans to file a request with the MPUC for an annual natural gas rate case in November 2023.

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 filing is based on a 2024 forecast test year, a ROE of 10.25%, an equity ratio of 52.5% and a forecasted average net rate base of approximately $2.1 billion for the electric utility and $284 million for the natural gas utility.

On Sept. 1, 2023, the Public Service Commission of Wisconsin (PSCW) Staff recommended an electric base rate decrease of $3 million or (0.3)% when including depreciation, fuel and purchased power adjustments and a natural gas rate increase of $5 million, or 3.1%. The recommendation was based on a ROE of 9.7% and an equity ratio of 52.5%.

In September 2023, NSP-Wisconsin filed rebuttal testimony and updated its request for depreciation life extensions and other updates. NSP-Wisconsin revised its requested rate increase to $25 million for the electric utility and $7 million for the natural gas utility. NSP-Wisconsin will update forecasted fuel costs before the Commission decision. Prudently incurred 2024 fuel costs will be trued up to actuals in a fuel reconciliation process, subject to a 2% band.

A PSCW decision is anticipated late fourth quarter 2023 with new rates effective in January 2024.

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 previously recovered through various rider mechanisms. The request was 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.

In September 2023, the Colorado Public Utility Commission (CPUC) approved a settlement between PSCo and various parties, which included the following terms:

•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.

•Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).

•Termination of the revenue decoupling pilot with implementation of new rates.

•Continuation of previously authorized trackers and deferrals.

•Collection of PSCo’s requested 2023 TCA revenues, previously suspended by the CPUC. Beginning in 2024, projects eligible for recovery will be limited to projects which increase transmission capacity or are part of an approved wildfire mitigation plan.

Rates became effective in September 2023.

PSCo — Colorado Resource Plan — In August 2022, the CPUC approved a settlement for the Colorado Resource Plan among PSCo and various intervenors. This settlement provides for an expected carbon reduction and the retirement of PSCo’s remaining coal plant by the end of 2030.

In September 2023, PSCo filed its recommended Preferred Plan. The filing also includes several other alternative scenarios. PSCo’s Preferred Plan results in the exit of coal by the end of 2030, roughly doubling wind and solar energy from 2022 levels, and reduction of greenhouse gas emissions by more than 80% from 2005 levels. It also reflects an average annual rate impact of approximately 2.3% which is inclusive of generation and transmission network and interconnection costs.

The Preferred Plan includes the following resources:


Generation Resource (in MW)	Company Owned	PPAs	Total
Wind Resources	2,531	875	3,406
Solar	1,109	860	1,969
Storage	500	670	1,170
Natural Gas	628	—	628
Biomass	19	—	19
Total	4,787	2,405	7,192

If approved by the CPUC, Xcel Energy expects to invest $7.9 billion in generation resources. In addition, the plan requires approximately $2.9 billion of incremental investments in transmission capacity upgrades and new lines to fully integrate the renewable generation.

The CPUC is expected to render a decision on the recommended Preferred Plan by the end of 2023 or in early 2024.

SPS — 2022 New Mexico Electric Rate Case — In November 2022, 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 October 2023, the NMPRC approved a settlement between SPS, New Mexico Public Regulation Commission (NMPRC) Staff, and various parties, which included the following terms:

•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.

Rates went into effect in October 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.

In September 2023, SPS and various parties reached a settlement in principle regarding the overall revenue requirement and key terms. The parties are still completing cost allocation and rate design settlement details and will file the settlement assuming finalization of remaining issues.

A PUCT decision is expected in the first quarter of 2024.

SPS New Mexico Resource Plan — In October 2023, SPS filed its Integrated Resource Plan (IRP) with the NMPRC, which supports projected load growth and secures replacement energy and capacity for retiring resources. SPS presented three load forecasts ranging from a low load growth scenario to a high load growth forecast (the “Electrification Forecast”). Based on these forecast scenarios, SPS’ initial IRP modeling projects a total resource need ranging from approximately 5,300 MW to 10,200 MW by 2030. Upon acceptance of the IRP, SPS expects to issue an RFP for new generation in mid-2024. The RFP will be evaluated in the latter half of 2024 with project selection expected in early 2025.

Note 5. New Technology and Government Grants

Hydrogen Hub Grant — In October 2023, the U.S. Department of Energy (DOE) selected the Heartland Hydrogen Hub, including multiple clean hydrogen projects from Xcel Energy, for award negotiations to receive up to $925 million. The Heartland Hydrogen Hub is one of seven selected to receive DOE funding. The hub includes Xcel Energy, Marathon Petroleum Corporation and TC Energy, in collaboration with the University of North Dakota’s Energy & Environmental Resource Center, to produce and use low-carbon hydrogen at commercial scale in Minnesota, Wisconsin, South Dakota, North Dakota and Montana. The hub aims to reduce carbon emissions by more than 1 million metric tons per year. Xcel Energy expects to receive a large portion of the federal award for its projects within the hub, subject to negotiations. In its application, Xcel Energy proposed investing approximately $2 billion over a decade for clean hydrogen producing equipment and infrastructure. Project detailed design will begin after the Heartland Hydrogen Hub finishes award negotiations. Project development will likely continue through 2035.

Form Energy Long Duration Storage Grant — In September 2023, the DOE awarded Xcel Energy a $70 million grant to support our two 10 MW, 100-hour battery pilots with Form Energy. Xcel Energy expects to develop a 10 MW 100-hour-battery storage unit at the Sherco retiring coal plant site in Minnesota and the Comanche retiring coal plant site in Colorado. Combined with grants from Breakthrough Energy’s Catalyst Fund, Xcel Energy has secured $90 million to support these pilots, which will reduce the costs of the projects for our customers. Long duration energy storage systems are critical to achieve 100% carbon free generation and strengthen the grid from the variability of renewable energy.

Wildfire/Extreme Weather Grant — In October 2023, the DOE awarded Xcel Energy $100 million to support projects to mitigate the threat of wildfires and ensure resiliency of the grid through extreme weather. Xcel Energy plans to match the grant with $140 million of investment. The projects will take a number of steps to boost grid resiliency, including adding fire-resistant coatings to 6,000 wood poles, improving equipment safety features in power lines and electric vehicle chargers in high fire risk conditions, moving high-risk distribution circuits underground, and enhancing vegetation management. They will also build on current programs using emerging technology, such as drones aided by artificial intelligence that inspect power lines for safety, wind strength testing, satellite identification of trees that pose a risk and modeling software to predict how fires would spread.

Joint Target Interconnection Queue (JTIQ) Grant — In October 2023, the DOE awarded a $464 million grant to Xcel Energy and several other utilities for five JTIQ projects. The projects are part of a collaboration between MISO and SPP that will help to fund the construction of high-voltage transmission lines that improve reliability and resolve constraints in the transmission system for up to 30 gigawatts of new generation. Xcel Energy is part of two of these project awards.

Note 6. Significant Litigation

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 Oct. 24, 2023, PSCo is aware of 14 complaints, certain of which have also named Xcel Energy Inc. as a defendant, on behalf of at least 675 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. 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.

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 per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles. Colorado law 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.

Comanche Unit 3 Litigation — In 2021, CORE Electric Cooperative (CORE) filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In April 2022, CORE filed a supplement to include damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches.

In February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. In September 2023, the court denied PSCo’s motion for summary judgment on other categories of damages and allowed CORE to seek approximately $253 million at trial (before interest), including an alleged $187 million reduction in the value of CORE’s ownership interest in the Comanche 3 facility and $60 million of alleged lost power costs.

On Oct. 25, 2023, the jury awarded CORE lost power damages of $26 million. PSCo recognized $34 million for the verdict in the third quarter of 2023, including estimated interest and other costs. PSCo intends to file an appeal of this decision.

Note 7. Non-GAAP Reconciliation

Xcel Energy’s reported earnings are prepared in accordance with GAAP. Xcel Energy’s management believes that ongoing earnings, or GAAP earnings adjusted for certain items, reflect management’s performance in operating the company and provides a meaningful representation of the underlying performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors and when communicating its earnings outlook to analysts and investors. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

Earnings Adjusted for Certain Items (Ongoing Earnings)

The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Millions of Dollars)	2023		2022		2023		2022
GAAP net income	$	656	$	649	$	1,362	$	1,357
Loss on Comanche Unit 3 Litigation	34		—		34		—
Less: tax effect of adjustment	(8)		—		(8)		—
Ongoing earnings	$	682	$	649	$	1,388	$	1,357

Comanche Unit 3 Litigation — As a result of an Oct. 25, 2023 jury verdict in Denver County District Court awarding CORE lost power damages and other costs, PSCo recognized a $34 million loss for the matter in the third quarter of 2023. Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings. See Note 6.

Note 8. Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023 ongoing earnings guidance is a narrowed range of $3.32 to $3.37 per share, from the original guidance 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% to 2%.

•Weather-normalized retail firm natural gas sales are projected to increase ~1%.

•Capital rider revenue is projected to increase $40 million to $50 million (net of PTCs).

•O&M expenses are projected to decline ~1% to 2%.

•Depreciation expense is projected to increase approximately $25 million to $35 million.

•Property taxes are projected to decrease $30 million to $35 million.

•Interest expense (net of AFUDC - debt) is projected to increase $90 million to $100 million.

•AFUDC - equity is projected to increase $10 million to $15 million.

•ETR is projected to be ~(9%) to (11%). The negative ETR is largely offset by PTCs flowing back to customers in the capital riders and fuel mechanisms and is largely earnings neutral.

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 projected levels unless noted:

•Constructive outcomes in all pending rate case and regulatory proceedings.

•Normal weather patterns for the year.

•Weather-normalized retail electric sales are projected to increase 2% to 3%.

•Weather-normalized retail firm natural gas sales are projected to increase ~1%.

•Capital rider revenue is projected to increase $35 million to $45 million (net of PTCs).

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

•Depreciation expense is projected to increase approximately $250 million to $260 million.

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

•Interest expense (net of AFUDC - debt) is projected to increase $115 million to $125 million.

•AFUDC - equity is projected to increase $40 million to $50 million.

•ETR is projected to be ~(4%) to (6%). The negative ETR is largely offset by PTCs flowing back to customers in the capital riders and fuel mechanisms and is largely earnings neutral.

(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.

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 base of $3.35 per share, which represents the mid-point of the original 2023 guidance range of $3.30 to $3.40 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.

XCEL ENERGY INC. AND SUBSIDIARIES

EARNINGS RELEASE SUMMARY (UNAUDITED)

(amounts in millions, except per share data)


	Three Months Ended Sept. 30
	2023		2022
Operating revenues:
Electric and natural gas	$	3,632	$	4,056
Other	30		26
Total operating revenues	3,662		4,082

Net income	$	656	$	649

Weighted average diluted common shares outstanding	552		548

Components of EPS — Diluted
Regulated utility	$	1.25	$	1.28
Xcel Energy Inc. and other costs	(0.06)		(0.09)
GAAP diluted EPS (a)	1.19		1.18
Loss on Comanche Unit 3 litigation (See Note 7)	0.05		—
Ongoing diluted EPS (a)	$	1.23	$	1.18

Book value per share	$	31.38	$	29.90
Cash dividends declared per common share	0.52		0.4875



	Nine Months Ended Sept. 30
	2023		2022
Operating revenues:
Electric and natural gas	$	10,677	$	11,178
Other	87		79
Total operating revenues	10,764		11,257

Net income	$	1,362	$	1,357

Weighted average diluted common shares outstanding	552		546

Components of EPS — Diluted
Regulated utility	$	2.68	$	2.69
Xcel Energy Inc. and other costs	(0.22)		(0.21)
GAAP and ongoing diluted EPS (a)	2.47		2.48
Loss on Comanche Unit 3 litigation (See Note 7)	0.05		—
Ongoing diluted EPS (a)	$	2.52	$	2.48

Book value per share	$	31.43	$	29.98
Cash dividends declared per common share	1.56		1.4625

(a)Amounts may not add due to rounding.