Xcel Energy Third Quarter 2020 Earnings Report

Rhea-AI Summary

Xcel Energy reported a third-quarter GAAP and ongoing earnings of $603 million, or $1.14 per share, in 2020, up from $527 million, or $1.01 per share, in 2019. The company narrowed its 2020 earnings guidance to $2.75 to $2.81 per share and provided a 2021 outlook of $2.90 to $3.00 per share. Plans for a $22.6 billion investment in base capital over five years include $1.4 billion to address COVID-19 impacts, aiming to create 5,000 jobs and expand its renewable energy portfolio. A 10-year vision aims to power 1.5 million electric vehicles by 2030.

Positive

• Third-quarter earnings increased to $603 million, or $1.14 per share, from $527 million, or $1.01 per share in 2019.
• Narrowed 2020 earnings guidance to $2.75 to $2.81 per share.
• Initiated 2021 earnings guidance of $2.90 to $3.00 per share.
• Plans to invest $22.6 billion in base capital over the next five years.
• Proposed $1.4 billion investment to mitigate COVID-19 impacts, creating 5,000 jobs.
• Vision to power 1.5 million electric vehicles by 2030, saving customers $1 billion on fueling costs.

Negative

• None.

MINNEAPOLIS--(BUSINESS WIRE)--Xcel Energy Inc. (NASDAQ: XEL) today reported 2020 third quarter GAAP and ongoing earnings of $603 million, or $1.14 per share, compared with $527 million, or $1.01 per share in the same period in 2019.

“Xcel Energy achieved strong third quarter results despite the ongoing pandemic and has launched important new initiatives to support our customers, employees and communities through these challenging times. As a result, we are narrowing our 2020 earnings guidance to $2.75 to $2.81 per share. In addition, we are initiating 2021 earnings guidance of $2.90 to $3.00 per share, which is consistent with our long-term growth objective,” said Ben Fowke, chairman and CEO of Xcel Energy.

“Over the next five years, we plan to invest $22.6 billion in base capital. We also have proposed to invest an incremental $1.4 billion related to requests from Minnesota to help address the economic impacts of COVID-19. Our proposal, which includes grid investment, solar facilities and modernizing aging wind farms, would create 5,000 jobs and expand our renewable portfolio, all while keeping customer bills low. It also outlines a 10-year vision to power 1.5 million electric vehicles, saving customers $1 billion on fueling costs and cutting carbon emissions by nearly 5 million tons annually by 2030.”

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:	(866) 575-6539
International Dial-In:	(400) 120-9101
Conference ID:	9230440

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 Investor Relations. If you are unable to participate in the live event, the call will be available for replay from 12:00 p.m. CDT on Oct. 29 through 12:00 p.m. CDT on Nov. 1.

Replay Numbers
US Dial-In:	(888) 203-1112
International Dial-In:	(719) 457-0820
Access Code:	9230440

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 2020 earnings per share (EPS) guidance, 2021 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future bad debt expense, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, and expectations regarding regulatory proceedings, 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, 2019 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 and their impact on capital expenditures and 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 CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (amounts in millions, except per share data)
		Three Months Ended Sept. 30										Nine Months Ended Sept. 30
		2020					2019					2020					2019
Operating revenues
Electric		$	2,941				$	2,771				$	7,430				$	7,345
Natural gas		219					222					1,082					1,324
Other		22					20					67					62
Total operating revenues		3,182					3,013					8,579					8,731
Operating expenses
Electric fuel and purchased power		981					952					2,611					2,679
Cost of natural gas sold and transported		54					55					425					646
Cost of sales — other		11					9					28					28
Operating and maintenance expenses		579					580					1,708					1,764
Conservation and demand side management expenses		73					75					215					212
Depreciation and amortization		513					447					1,449					1,319
Taxes (other than income taxes)		158					137					453					429
Total operating expenses		2,369					2,255					6,889					7,077
Operating income		813					758					1,690					1,654
Other income (expense), net		1					8					(6		)			14
Equity earnings of unconsolidated subsidiaries		12					10					29					29
Allowance for funds used during construction — equity		30					15					91					55
Interest charges and financing costs
Interest charges — includes other financing costs of $7, $6, $21 and $19, respectively		221					199					628					578
Allowance for funds used during construction — debt		(11		)			(7		)			(33		)			(27		)
Total interest charges and financing costs		210					192					595					551
Income before income taxes		646					599					1,209					1,201
Income tax expense		43					72					24					121
Net income		$	603				$	527				$	1,185				$	1,080
Weighted average common shares outstanding:
Basic		526					519					526					517
Diluted		528					521					527					518
Earnings per average common share:
Basic		$	1.15				$	1.02				$	2.25				$	2.09
Diluted		1.14					1.01					2.25					2.08

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), electric margin, natural gas margin, 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 excludes (or includes) amounts that are adjusted from 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.

Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales - other, operating and maintenance (O&M) expenses, conservation and demand side management (DSM) expenses, depreciation and amortization and taxes (other than income taxes).

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 is calculated by dividing the net income or loss of each subsidiary, 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 of 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 nine months ended Sept. 30, 2020 and 2019, 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 2020 third quarter earnings were $1.14 per share compared to $1.01 per share in 2019, primarily reflecting higher electric margin (largely due to capital investment recovery) and allowance for funds used during construction (AFUDC), which offset increased depreciation and declining sales due to the impacts of COVID-19. Third quarter sales declined on a weather-adjusted basis, but exceeded our previous assumptions. There continues to be uncertainty related to the impact of the pandemic on the remainder of the year.

All companies were negatively impacted by the pandemic starting in March 2020 and continuing into the third quarter. See Note 5 for further information regarding COVID-19, including estimated impact on weather-adjusted electric sales.

Summarized diluted EPS for Xcel Energy:

		Three Months Ended Sept. 30										Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share		2020					2019					2020					2019
NSP-Minnesota		$	0.46				$	0.40				$	0.89				$	0.81
PSCo		0.42					0.39					0.87					0.86
SPS		0.24					0.20					0.46					0.42
NSP-Wisconsin		0.08					0.06					0.16					0.12
Equity earnings of unconsolidated subsidiaries		0.01					0.01					0.04					0.04
Regulated utility (a)		1.21					1.06					2.42					2.24
Xcel Energy Inc. and Other		(0.07		)			(0.05		)			(0.17		)			(0.16		)
Total (a)		$	1.14				$	1.01				$	2.25				$	2.08
(a) Amounts may not add due to rounding.

NSP-Minnesota — Earnings increased $0.06 per share for the third quarter of 2020 and $0.08 per share year-to-date. Year-to-date results reflect lower O&M expenses and higher electric margin (regulatory outcomes offset lower sales primarily due to COVID-19), partially offset by increased depreciation and lower natural gas margin.

PSCo — Earnings increased $0.03 per share for the third quarter of 2020 and $0.01 per share year-to date. The increase in year-to-date earnings was driven by higher electric margin (regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and reduced O&M expenses, partially offset by higher depreciation, interest expense and taxes (other than income taxes).

SPS — Earnings increased $0.04 per share for the third quarter of 2020 and $0.04 per share year-to-date. Year-to-date results reflect higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes).

NSP-Wisconsin — Earnings increased $0.02 per share for the third quarter of 2020 and $0.04 per share year-to-date. The increase in year-to-date earnings was driven by higher electric margin (2020 Wisconsin Fuel Settlement offset lower sales due to COVID-19) and AFUDC, as well as lower O&M expenses. These items were partially offset by increased depreciation and lower natural gas margin.

Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company.

Components significantly contributing to changes in 2020 EPS compared with the same period in 2019:

Diluted Earnings (Loss) Per Share		Three Months Ended Sept. 30					Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS - 2019		$	1.01				$	2.08
Components of change - 2020 vs. 2019
Higher electric margin (a)		0.20					0.22
Lower ETR (b)		0.07					0.17
Lower O&M		—					0.08
Higher AFUDC		0.03					0.07
Higher depreciation and amortization		(0.09		)			(0.19		)
Higher interest charges		(0.03		)			(0.07		)
Lower natural gas margins		—					(0.03		)
Lower other income (expense), net		(0.01		)			(0.03		)
Other (net)		(0.04		)			(0.05		)
GAAP and ongoing diluted EPS - 2020		$	1.14				$	2.25

^(a) Period-over-period change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 as follows:

	Diluted Earnings (Loss) Per Share		Three Months Ended Sept. 30					Nine Months Ended Sept. 30
	Electric margin (excluding reductions in sales and demand)		$	0.21				$	0.30
	Reductions in sales and demand (*)		(0.01		)			(0.08		)
	Higher electric margins		$	0.20				$	0.22
	(*) Sales decline excludes weather impact, net of decoupling/sales true-up and decrease in demand revenue is net of sales true-up.

^(b) Includes production tax credits (PTCs) and tax reform regulatory amounts, which are primarily offset in electric margin.

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.

Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. Cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to 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.

Percentage increase (decrease) in normal and actual HDD, CDD and THI:

	Three Months Ended Sept. 30									Nine Months Ended Sept. 30
	2020 vs. Normal			2019 vs. Normal			2020 vs. 2019			2020 vs. Normal			2019 vs. Normal			2020 vs. 2019
HDD	48.4	%		(64.0)	%		251.2	%		(2.8)	%		10.7	%		(11.2)	%
CDD	20.7			27.4			1.3			21.2			6.4			21.3
THI	4.6			(2.6)			8.3			7.0			(8.2)			18.3

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

	Three Months Ended Sept. 30												Nine Months Ended Sept. 30
	2020 vs. Normal				2019 vs. Normal				2020 vs. 2019				2020 vs. Normal				2019 vs. Normal				2020 vs. 2019
Retail electric	$	0.079			$	0.040			$	0.039			$	0.096			$	0.035			$	0.061
Decoupling and sales true-up	(0.035)				—				(0.035)				(0.044)					0.001			(0.045)
Electric total	$	0.044			$	0.040			$	0.004			$	0.052			$	0.036			$	0.016
Firm natural gas	—				(0.001)				0.001				(0.005)				0.021				(0.026)
Total	$	0.044			$	0.039			$	0.005			$	0.047			$	0.057			$	(0.010)

Sales — Sales growth (decline) for actual and weather-normalized sales in 2020 compared to the same period in 2019:

		Three Months Ended Sept. 30
		PSCo				NSP-Minnesota				SPS				NSP-Wisconsin				Xcel Energy
Actual (a)
Electric residential		8.7	%			11.8	%			4.4	%			6.6	%			9.1	%
Electric C&I		(4.5	)			(5.2	)			(5.5	)			(4.1	)			(5.0	)
Total retail electric sales		(0.1	)			0.1				(3.5	)			(1.2	)			(0.9	)
Firm natural gas sales		1.1				2.1				N/A				11.2				2.0

		Three Months Ended Sept. 30
		PSCo				NSP-Minnesota				SPS				NSP-Wisconsin				Xcel Energy
Weather-Normalized (a)
Electric residential		3.8	%			4.3	%			2.2	%			2.0	%			3.7	%
Electric C&I		(4.2	)			(5.3	)			(5.0	)			(4.6	)			(4.8	)
Total retail electric sales		(1.6	)			(2.3	)			(3.5	)			(2.7	)			(2.4	)
Firm natural gas sales		(4.8	)			(1.8	)			N/A				6.6				(3.3	)

		Nine Months Ended Sept. 30
		PSCo				NSP-Minnesota				SPS				NSP-Wisconsin				Xcel Energy
Actual (a)
Electric residential		6.9	%			5.6	%			5.0	%			2.9	%			5.8	%
Electric C&I		(4.2	)			(7.3	)			(3.4	)			(5.6	)			(5.2	)
Total retail electric sales		(0.7	)			(3.4	)			(2.0	)			(3.2	)			(2.2	)
Firm natural gas sales		(7.3	)			(9.3	)			N/A				(9.9	)			(8.1	)

		Nine Months Ended Sept. 30
		PSCo				NSP-Minnesota				SPS				NSP-Wisconsin				Xcel Energy
Weather-Normalized (a)
Electric residential		3.5	%			3.3	%			2.0	%			2.7	%			3.2	%
Electric C&I		(4.7	)			(7.5	)			(3.5	)			(5.8	)			(5.5	)
Total retail electric sales		(2.1	)			(4.2	)			(2.6	)			(3.4	)			(3.1	)
Firm natural gas sales		(1.7	)			2.2				N/A				3.6				(0.2	)

		Nine Months Ended Sept. 30 (Leap Year Adjusted)
		PSCo				NSP-Minnesota				SPS				NSP-Wisconsin				Xcel Energy
Weather-Normalized (a)
Electric residential		3.2	%			3.0	%			1.6	%			2.3	%			2.8	%
Electric C&I		(5.1	)			(7.8	)			(3.9	)			(6.2	)			(5.8	)
Total retail electric sales		(2.5	)			(4.6	)			(3.0	)			(3.8	)			(3.5	)
Firm natural gas sales		(2.5	)			1.4				N/A				2.8				(1.0	)

^(a) Higher residential sales and lower commercial and industrial (C&I) sales were primarily attributable to COVID-19.

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

• PSCo — Residential sales rose based on higher use per customer from increased working from home and an increased number of customers. The decline in C&I sales was primarily due to the economic contraction from COVID-19, particularly noted within the manufacturing and service industries.
• NSP-Minnesota — Residential sales growth reflects higher use per customer from increased working from home and an increase in customers. Decrease in C&I sales were driven by the energy, manufacturing and services sectors, primarily related to COVID-19.
• SPS — Residential sales increased due to customer growth and higher use per customer from increased working from home. The decline in C&I sales was driven by shutdowns of the economy from COVID-19, primarily within the energy and manufacturing sectors.
• NSP-Wisconsin — Residential sales growth was attributable to higher use per customer from increased working from home and customer additions. The decline in C&I sales was largely related to COVID-19, specifically decreased sales to the manufacturing sector.

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

• Natural gas sales reflect primarily lower C&I customer use due to the economic contraction from COVID-19, partially offset by an increase in number of residential and C&I customers.

Electric Margin — 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 have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. In addition, electric customers receive a credit for PTCs generated, which reduced electric revenue and margin.

Electric revenues and margin:

		Three Months Ended Sept. 30										Nine Months Ended Sept. 30
(Millions of Dollars)		2020					2019					2020					2019
Electric revenues		$	2,941				$	2,771				$	7,430				$	7,345
Electric fuel and purchased power		(981		)			(952		)			(2,611		)			(2,679		)
Electric margin		$	1,960				$	1,819				$	4,819				$	4,666

Changes in electric margin:

(Millions of Dollars)		Three Months Ended Sept. 30, 2020 vs. 2019					Nine Months Ended Sept. 30, 2020 vs. 2019
Regulatory rate outcomes (Colorado, Wisconsin, Texas and New Mexico) (a)		$	123				$	158
Non-fuel riders		19					43
Wholesale transmission revenue (net)		10					35
MEC purchased capacity costs (b)		4					35
Estimated impact of weather (net of decoupling/sales true-up)		4					12
PTCs flowed back to customers (offset by lower ETR)		(28		)			(81		)
Sales and demand (c)		(9		)			(56		)
Other (net)		18					7
Total increase in electric margin		$	141				$	153

(a)	Includes approximately $70 million of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs, see Note 4 for additional information.
(b)	Prior to the Mankato Energy Center (MEC) acquisition (first quarter of 2020), all purchased power costs were recorded as a component of electric fuel and purchased power. During Xcel Energy’s ownership of MEC, all non-fuel related costs including depreciation, O&M and interest expenses were recorded within separate statement of income line items in our consolidated financial results. MEC was sold in the third quarter of 2020.
(c)	Sales increase (decline) excludes weather impact, net of decoupling/sales true-up, and decrease in demand revenue is net of sales true-up.

Natural Gas Margin — Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to cost recovery mechanisms.

Natural gas revenues and margin:

		Three Months Ended Sept. 30										Nine Months Ended Sept. 30
(Millions of Dollars)		2020					2019					2020					2019
Natural gas revenues		$	219				$	222				$	1,082				$	1,324
Cost of natural gas sold and transported		(54		)			(55		)			(425		)			(646		)
Natural gas margin		$	165				$	167				$	657				$	678

Changes in natural gas margin:

(Millions of Dollars)		Three Months Ended Sept. 30, 2020 vs. 2019					Nine Months Ended Sept. 30, 2020 vs. 2019
Estimated impact of weather		$	1				$	(18	)
Retail sales decline		(1		)			(2		)
Regulatory rate outcomes (Wisconsin)		—					(2		)
Transport sales		1					(1		)
Infrastructure and integrity riders		1					6
Other (net)		(4		)			(4		)
Total decrease in natural gas margin		$	(2	)			$	(21	)

O&M Expenses — O&M expenses decreased $1 million, or 0.2%, for the third quarter and $56 million, or 3.2%, year-to-date, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19. Significant changes are summarized as follows:

(Millions of Dollars)		Three Months Ended Sept. 30, 2020 vs. 2019					Nine Months Ended Sept. 30, 2020 vs. 2019
Distribution		$	(10	)			$	(40	)
Transmission		(4		)			(10		)
Generation		(3		)			(8		)
Texas rate case deferral		13					5
Other (net)		3					(3		)
Total decrease in O&M expenses		$	(1	)			$	(56	)

• Distribution declined due to cost mitigation/continuous improvement efforts and the timing of maintenance activities.
• Transmission declined due to cost mitigation/continuous improvement initiatives.
• Generation was lower from timing of maintenance and overhauls at power plants and cost mitigation/continuous improvement efforts, which were partially offset by an increase in wind related O&M expenses from our renewable expansion.
• Texas rate case deferral amounts were due to recognition of previously deferred amounts related with the Texas Electric Rate Case.
• Included within Other (net) are amounts associated with the sale of MEC. During the third quarter of 2020, Xcel Energy recognized a net gain of approximately $20 million on the sale, which was offset by charitable giving, including COVID-19 relief efforts.

Depreciation and Amortization — Depreciation and amortization increased $66 million, or 14.8%, for the third quarter and $130 million, or 9.9%, year-to-date. Increase was primarily driven by Hale, Lake Benton, Foxtail, Blazing Star I and Cheyenne Ridge wind facilities going into service, as well as normal system expansion. In addition, new depreciation rates were implemented in Colorado, New Mexico and Texas as part of regulatory outcomes in 2020.

Other Income (Expense) — Other income (expense) decreased $7 million for the third quarter and $20 million year-to-date. The decrease was substantially due to the performance of rabbi trust investments primarily in the first half of 2020, which was offset in O&M expenses.

AFUDC, Equity and Debt — AFUDC increased $19 million for the third quarter and $42 million year-to-date. Increase was primarily due to various wind projects under construction.

Interest Charges — Interest charges increased $22 million, or 11.1%, for the third quarter and $50 million, or 8.7% 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.

Income Taxes — Income taxes decreased $29 million for the third quarter. The decrease was primarily driven by an increase in wind PTCs, an increase in plant regulatory differences and a carryback tax benefit, partially offset by higher pretax earnings. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The effective tax rate (ETR) was 6.7% for the third quarter of 2020 compared with 12.0% for 2019.

Income taxes decreased $97 million year-to-date. The decrease was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences. Wind PTCs are credited to customers and do not have a material impact on net income. The ETR was 2.0% for the first nine months ending Sept. 30, 2020 compared with 10.1% for 2019.

Additional details:

		Three Months Ended Sept. 30									Nine Months Ended Sept. 30
		2020			2019			2020 vs 2019			2020			2019			2020 vs 2019
Federal statutory rate		21.0	%		21.0	%		—	%		21.0	%		21.0	%		—	%
State tax (net of federal tax effect)		5.0			5.0			—			5.1			5.0			0.1
(Decreases) increases:
Wind PTCs		(8.0)			(6.1)			(1.9)			(13.2)			(8.1)			(5.1)
Plant regulatory differences (a)		(7.2)			(5.6)			(1.6)			(7.4)			(5.5)			(1.9)
Net Operating Loss carryback		(1.9)			—			(1.9)			(1.0)			—			(1.0)
Other tax credits and NOL allowances (net)		(1.0)			(1.7)			0.7			(1.2)			(1.8)			0.6
Other (net)		(1.2)			(0.6)			(0.6)			(1.3)			(0.5)			(0.8)
Effective income tax rate		6.7	%		12.0	%		(5.3)	%		2.0	%		10.1	%		(8.1)	%

(a)	Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers. Income tax benefits associated with the credit of excess deferred credits are generally offset by corresponding revenue reductions.

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

Xcel Energy’s capital structure:

(Millions of Dollars)		Sept. 30, 2020				Percentage of Total Capitalization			Dec. 31, 2019				Percentage of Total Capitalization
Current portion of long-term debt		$	401			1	%		$	702			2	%
Short-term debt		500				1			595				2
Long-term debt		19,960				58			17,407				54
Total debt		20,861				60			18,704				58
Common equity		13,777				40			13,239				42
Total capitalization		$	34,638			100	%		$	31,943			100	%

Liquidity — As of Oct. 26, 2020, 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.		$	1,250			$	—			$	1,250			$	269			$	1,519
PSCo		700				8				692				2				694
NSP-Minnesota		500				10				490				202				692
SPS		500				16				484				1				485
NSP-Wisconsin		150				10				140				—				140
Total		$	3,100			$	44			$	3,056			$	474			$	3,530
Term Loan (c)		500				500				—

(a)	Credit facilities expire in June 2024.
(b)	Includes outstanding commercial paper and letters of credit.
(c)	The $500 million term loan matures in December 2020.

Term Loan Agreements — In December 2019, Xcel Energy Inc. extended a $500 million Term Loan Agreement for an additional 364 days. In September 2020, Xcel Energy Inc. repaid its $700 million 364-Day Term Loan Agreement that was entered into in March 2020.

Bilateral Credit Agreement — In March 2020, 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 $46 million of outstanding letters of credits as of Sept. 30, 2020.

Forward Equity Agreements — In November 2019, Xcel Energy Inc. entered into forward equity agreements in connection with a $743 million public offering of 11.8 million shares, which is expected to be settled in shares later in 2020.

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. 26, 2020:

Credit Type		Company		Moody’s		S&P Global Ratings		Fitch
Senior Unsecured Debt		Xcel Energy Inc.		Baa1		BBB+		BBB+
Senior Secured Debt		NSP-Minnesota		Aa3		A		A+
		NSP-Wisconsin		Aa3		A		A+
		PSCo		A1		A		A+
		SPS		A3		A		A-
Commercial Paper		Xcel Energy Inc.		P-2		A-2		F2
		NSP-Minnesota		P-1		A-2		F2
		NSP-Wisconsin		P-1		A-2		F2
		PSCo		P-2		A-2		F2
		SPS		P-2		A-2		F2

Capital Expenditures — Base capital expenditures and incremental capital forecasts for Xcel Energy for 2021 through 2025 are as follows:

		Base Capital Forecast (Millions of Dollars)
By Regulated Utility		2021					2022					2023				2024				2025				2021 - 2025 Total
PSCo		$	1,700				$	1,835				$	1,750			$	1,695			$	1,655			$	8,635
NSP-Minnesota		1,630					1,605					1,635				1,645				1,890				8,405
SPS		505					710					770				735				675				3,395
NSP-Wisconsin		360					430					395				515				470				2,170
Other (a)		(20		)			(15		)			10				10				10				(5		)
Total base capital expenditures		$	4,175				$	4,565				$	4,560			$	4,600			$	4,700			$	22,600

		Base Capital Forecast (Millions of Dollars)
By Function		2021				2022				2023				2024				2025				2021 - 2025 Total
Electric distribution		$	1,205			$	1,440			$	1,550			$	1,505			$	1,475			$	7,175
Electric transmission		870				1,285				1,285				1,270				1,290				6,000
Electric generation		630				575				560				750				975				3,490
Natural gas		615				615				665				670				625				3,190
Other		545				575				485				405				335				2,345
Renewables		310				75				15				—				—				400
Total base capital expenditures		$	4,175			$	4,565			$	4,560			$	4,600			$	4,700			$	22,600
(a) Other category includes intercompany transfers for safe harbor wind turbines.

		Incremental Capital Forecast (Millions of Dollars) (a)
NSP-Minnesota Proposal		2021				2022				2023				2024				2025				2021 - 2025 Total
Wind repowering		$	150			$	180			$	150			$	270			$	—			$	750
Solar proposal		40				150				460				—				—				650
Total incremental capital		$	190			$	330			$	610			$	270			$	—			$	1,400
(a) Reflects proposed capital investment filed under the Minnesota Relief and Recovery plan, which is pending a MPUC decision. The incremental capital investment is not included in the base capital forecast.

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, 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 2025 — 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 2021 through 2025:

(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations (a)		$	14,680
New Debt (b)		7,260
Equity through the DRIP and Benefit Program		410
Other Equity		250
Base Capital Expenditures 2021-2025		$	22,600
Maturing Debt		$	4,120

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

The incremental renewable capital proposed in the Minnesota Relief and Recovery plan would be financed with approximately 50% debt and 50% equity, if approved by the MPUC.

2020 Financing Activity — During 2020, Xcel Energy plans to issue approximately $75 to $80 million of equity through the DRIP and benefit programs. In addition, Xcel Energy Inc. and its utility subsidiaries issued the following:

Issuer

Security

Amount

Status

Tenor

Coupon

Xcel Energy Inc.

Senior Unsecured Notes

$

600

Completed

10 Year

3.40

%

NSP-Minnesota

First Mortgage Bonds

700

Completed

31 Year

2.60

NSP-Wisconsin

First Mortgage Bonds

100

Completed

31 Year

3.05

PSCo

First Mortgage Bonds

375

Completed

31 Year

2.70

PSCo

First Mortgage Bonds

375

Completed

11 Year

1.90

SPS

First Mortgage Bonds

350

Completed

30 Year

3.15

Xcel Energy Inc.

Senior Unsecured Notes

500

Completed

3 Year

0.50

2021 Planned Debt Financing — During 2021, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:

• NSP-Minnesota — approximately $400 million of first mortgage bonds;
• NSP-Wisconsin — approximately $100 million of first mortgage bonds;
• PSCo — approximately $400 million of first mortgage bonds; and
• SPS — approximately $150 million of first mortgage bonds.

Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.

Note 4. Rates and Regulation

Minnesota Relief and Recovery — In 2020, the Minnesota Public Utilities Commission (MPUC) opened a docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19. NSP-Minnesota’s filing included the following components:

• In September 2020, NSP-Minnesota proposed to accelerate approximately $865 million of grid investment and sought approval for approximately $150 million of incremental electric vehicle rebates.
• In September 2020, NSP-Minnesota proposed to repower 651 MW of owned wind projects with a capital investment of approximately $750 million. In addition, developers proposed repowering 67 MW of wind projects under power purchase agreements (PPAs). NSP-Minnesota estimates over $160 million in customers savings over the life of the projects. NSP-Minnesota has requested a decision from the MPUC by year-end.
• In the first quarter of 2021, NSP-Minnesota plans to propose solar facilities of approximately 460 MW with an incremental investment of approximately $650 million. NSP-Minnesota anticipates a MPUC decision in the second or third quarter of 2021.

NSP-Wisconsin Solar Proposal — In October 2020, NSP-Wisconsin filed for a 74 MW solar facility build-own-transfer in Wisconsin for approximately $100 million. A Public Service Commission of Wisconsin decision is expected in the third quarter of 2021.

PSCo 2020 Rider Filings — In July 2020, PSCo filed rider requests with the Colorado Public Utilities Commission (CPUC) instead of filing a comprehensive electric rate case in 2020.

Wildfire Protection Rider — Seeks to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. In August 2020, the CPUC referred it to an Administrative Law Judge (ALJ).

Procedural schedule:

• Answer testimony Nov. 20, 2020;
• Rebuttal testimony Dec. 18, 2020;
• Settlement by Jan. 8, 2021;
• Hearing Jan. 14, 2021 - Jan. 15, 2021 and
• Statutory deadline March 24, 2021.

The rider is expected to be effective in June 2021 and continue through 2025. Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:

(Millions of Dollars)		2021			2022			2023			2024			2025
Forecasted annual revenue requirement		$	17		$	24		$	29		$	32		$	34

Advanced Grid Rider — Seeks to establish a rider to recover incremental costs associated with the Advanced Grid Intelligence and Security Initiative (AGIS). In August 2020, the CPUC referred the matter to an ALJ. In September 2020, the Office of Consumer Counsel filed a motion to dismiss the Advanced Grid Rider.

Procedural schedule:

• Answer testimony Dec. 9, 2020;
• Rebuttal Jan. 8, 2021;
• Settlement by Jan. 20, 2021;
• Hearing Jan. 25, 2021 - Jan 28, 2021; and
• Statutory deadline April 24, 2021.

The rider is expected to be effective in May 2021 and continue through 2025. The PSCo portion of the AGIS capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:

(Millions of Dollars)		2021			2022			2023			2024			2025
Forecasted annual revenue requirement		$	53		$	69		$	83		$	89		$	99

PSCo KEPCO Filing — In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021.

PSCo — Colorado 2020 Natural Gas Rate Case — In October 2020, the CPUC accepted a recommended decision by the ALJ to approve a comprehensive settlement without modification between PSCo, the CPUC Staff and various intervenors. The rate outcome results in a net increase to retail gas rates of $77 million, reflecting a $94 million increase in base rate revenue, partially offset by $17 million of costs previously authorized through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 and will be retroactively effective back to November 2020. The settlement is based on:

• A ROE of 9.20%;
• An equity ratio of 55.62%; and
• A historic test year as of Sept. 30, 2019, utilizing a year-end rate base and incorporating a known and measurable adjustment for the Tungsten to Black Hawk pipeline.

PSCo — Boulder Municipalization — In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues.

In September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement would result in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. The citizens of Boulder will vote on Nov. 3, 2020, whether to approve or deny the franchise agreement.

SPS — Texas 2019 Electric Rate Case — In August 2020, the Public Utility Commission of Texas approved a settlement between SPS and intervening parties, which reflects the following terms, retroactive to Sept. 12, 2019.

• An electric rate increase of $88 million;
• ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes;
• Acceleration of the depreciation life of the Tolk coal plant; and
• Ring-fencing measures, similar to other Texas utilities.

SPS expects to submit a filing in the fourth quarter of 2020 to surcharge the final under-recovered amount, which is estimated to be approximately $70 million, offset by the recognition of previously deferred costs. The impact of the retroactive amounts (related to period prior to Sept. 1, 2020) is as follows:

(Millions of Dollars)		Nine Months Ended Sept. 30, 2020
Revenue surcharge accrual		$	70
Depreciation and amortization		(37		)
O&M expense		(15		)
Interest expense		(11		)
Taxes other than income taxes		(7		)

Note 5. COVID-19

Although COVID-19 represents an unprecedented event that has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will allow us to continue to proactively manage and successfully navigate the challenges, risks and uncertainties associated with the pandemic. In addition, we have implemented O&M contingency plans to reduce costs and seek regulatory deferral mechanisms to offset the negative impact of the pandemic on sales, bad debt and other aspects of our business.

There is continued uncertainty regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs and the level and pace of economic recovery. Also, while we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of the pandemic, which could have a material impact on our results of operations, financial condition or cash flow.

An overview of certain risk considerations or areas which have or could significantly impact us is as follows.

Sales — In the first nine months of 2020, Xcel Energy experienced a decline in weather and leap year adjusted sales due to the impacts of COVID-19.

Xcel Energy has decoupling and sales true-up mechanisms in Minnesota (all electric classes) and Colorado (residential and non-demand SC&I electric classes), which mitigate the impact of changes to sales levels as compared to a baseline. In April 2020, Xcel Energy estimated the following potential impact of the pandemic on electric and natural gas sales and EPS:

• Weather-adjusted electric retail sales were projected to decline ~4% for 2020 (based on an increase of ~1% in residential sales and a decline of 6% in C&I sales).
• Weather-adjusted firm natural gas sales were projected to decline ~1%.
• Projected sales decline were estimated to reduce EPS by approximately $0.17.
• Other potential items could have negative EPS impact of $0.02 to $0.05, assuming constructive regulatory treatment.

However, our year-to-date weather and leap-year adjusted electric sales declined 3.5%, which was better than anticipated. As a result, we now expect weather and leap-year adjusted electric sales to decline by approximately 3% for the full-year of 2020. In comparison, our original 2020 earnings guidance assumed sales growth of approximately 1%.

Bad Debt — In March 2020, Xcel Energy announced it would not disconnect residential customers’ electric or natural gas service during the virus outbreak. In addition, certain states have issued limitations on charging late fees and extended protection to other customer classes. Bad debt expense could significantly increase due to regulatory orders, pandemic related economic impacts and customer hardship. However, several of our commissions have approved the deferral of incremental COVID-19 related expense, including bad debt expense as discussed below.

Regulatory — Xcel Energy has received orders in Minnesota, Colorado, Wisconsin, Texas, New Mexico, South Dakota and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. Xcel Energy has also filed requests in North Dakota to record a regulatory asset and defer all incremental expenses related to the pandemic.

The majority of wholesale customers are subject to formula transmission and production rates, which true-up rates to actual costs to serve.

Xcel Energy deferred approximately $6 million of related expenses as of Sept. 30, 2020. We will continue to monitor these costs and assess whether the actions of the regulator provide the evidence necessary to defer amounts as regulatory assets.

Contingency Plan — Xcel Energy has implemented contingency plans to reduce costs to offset the negative impact of COVID-19. Based on these actions and our year-to-date sales, we now expect 2020 O&M expenses will decline 1% to 2% compared with 2019.

Supply Chain and Capital Expenditures — Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. During the first nine months of 2020, Xcel Energy did not experience supply chain, contractor or employee disruptions that prevented us from performing maintenance or construction activity with the exception of delays in certain wind projects. However, we have not significantly adjusted our 2020 capital expenditure plan.

Pension — The funded status of the Xcel Energy pension plans was approximately 90% in January 2020. The funded status of the pension plan is currently estimated to be approximately 85%.

Xcel Energy does not expect any material changes to its pension funding requirement at this time. In addition, Xcel Energy has pension trackers in Colorado and Texas, which allow us to defer amounts above or below a baseline.

Liquidity — Xcel Energy has taken steps to enhance its liquidity and believes it has more than adequate liquidity. We have completed our debt issuance plans for 2020. As a result of these actions, Xcel Energy had approximately $3.5 billion of available liquidity as of Oct. 26, 2020.

Furthermore, Xcel Energy has an outstanding forward equity agreement in connection with a $743 million public offering of 11.8 million shares. These shares have not been issued and we expect to settle this equity forward later in 2020, which will further enhance liquidity. Finally, Xcel Energy continues to have access to the capital markets on favorable terms.

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

Xcel Energy 2020 Earnings Guidance — Xcel Energy narrows 2020 GAAP and ongoing earnings guidance to $2.75 to $2.81 from $2.73 to $2.83 per share ^{(a) (b)}, which assumes the implementation of contingency plans will be sufficient to offset the negative impacts of COVID-19.

Key assumptions as compared with 2019 levels unless noted:

• Constructive outcomes in all rate case and regulatory proceedings.
• Normal weather patterns for the remainder of the year.
• Weather-normalized retail electric sales are projected to decline ~3%.
• Weather-normalized retail firm natural gas sales are projected to be relatively flat.
• Capital rider revenue is projected to increase $40 million to $45 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.
• O&M expenses are projected to decline approximately 1% to 2%.
• Depreciation expense is projected to increase approximately $180 million to $190 million.
• Property taxes are projected to increase approximately $35 million to $45 million.
• Interest expense (net of AFUDC - debt) is projected to increase $60 million to $65 million.
• AFUDC - equity is projected to increase approximately $35 million to $45 million.
• ETR is projected to be ~0%. The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.

Xcel Energy 2021 Earnings Guidance — Xcel Energy’s 2021 GAAP and ongoing earnings guidance is a range of $2.90 to $3.00 per share.^(a)(b)

Key assumptions as compared with 2020 levels unless noted:

• Constructive outcomes in all rate case and regulatory proceedings.
• Modest impacts from COVID-19.
• 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 relatively flat.
• Capital rider revenue is projected to increase $125 million to $135 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.
• O&M expenses are projected to increase approximately 1%.
• Depreciation expense is projected to increase approximately $210 million to $220 million.
• Property taxes are projected to increase approximately $45 million to $55 million.
• Interest expense (net of AFUDC - debt) is projected to increase $0 million to $10 million.
• AFUDC - equity is projected to decline approximately $45 million to $55 million.
• ETR is projected to be ~(9%). The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.

(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. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
(b)	The global outbreak of COVID-19 is currently impacting countries, communities, supply chains and markets. The ultimate severity of this event is uncertain and could have a material impact on our liquidity, financial condition, or results of operations.

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 2020 base of $2.78 per share, which represents the mid-point of the original 2020 guidance range of $2.73 to $2.83 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
		2020					2019
Operating revenues:
Electric and natural gas		$	3,160				$	2,993
Other		22					20
Total operating revenues		3,182					3,013
Net income		$	603				$	527
Weighted average diluted common shares outstanding		528					521
Components of EPS — Diluted
Regulated utility		$	1.21				$	1.06
Xcel Energy Inc. and other costs		(0.07		)			(0.05		)
GAAP and ongoing diluted EPS (a)(b)		$	1.14				$	1.01
Book value per share		$	26.10				$	25.22
Cash dividends declared per common share		0.43					0.41

		Nine Months Ended Sept. 30
		2020					2019
Operating revenues:
Electric and natural gas		$	8,512				$	8,669
Other		67					62
Total operating revenues		8,579					8,731
Net income		$	1,185				$	1,080
Weighted average diluted common shares outstanding		527					518
Components of EPS — Diluted
Regulated utility		$	2.42				$	2.24
Xcel Energy Inc. and other costs		(0.17		)			(0.16		)
GAAP and ongoing diluted EPS (a)(b)		$	2.25				$	2.08
Book value per share		$	26.15				$	25.35
Cash dividends declared per common share		1.29					1.22

(a)	For the three and nine months ended Sept. 30, 2020 and 2019, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.
(b)	Amounts may not add due to rounding.