Exhibit 99.01

	414 Nicollet Mall
Jan. 28, 2021	Minneapolis, MN 55401

XCEL ENERGY

2020 YEAR END EARNINGS REPORT

•2020 earnings per share were $2.79 compared with $2.64 per share in 2019.

•Xcel Energy reaffirms 2021 EPS earnings guidance of $2.90 to $3.00 per share.

MINNEAPOLIS — Xcel Energy Inc. (NASDAQ: XEL) today reported 2020 GAAP and ongoing earnings of $1.47 billion, or $2.79 per share, compared with $1.37 billion, or $2.64 per share in the same period in 2019.

“Xcel Energy had a strong year despite the challenges brought on by COVID-19,” said Ben Fowke, chairman and CEO. “We achieved major milestones while keeping our employees and customers safe and are well positioned for the coming year and beyond.”

“I’m proud of the support we provided our communities, committing nearly $20 million to short and long-term corporate giving. Our $750 million plan to repower several wind farms in Minnesota was approved, which is expected to result in substantial customer savings and jobs creation. In Colorado, we received approval for an electric vehicle plan and are excited about the related opportunities. We also announced the early retirement of the Hayden and Craig coal plants and plans to convert our Harrington facility to natural gas. These achievements move us closer to achieving our goals of an 80% carbon reduction by 2030 and delivering 100% carbon-free electricity by 2050.”

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:	(888) 394-8218
International Dial-In:	(400) 120-8590
Conference ID:	6174235

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 Jan. 28 through 12:00 p.m. CDT on Jan. 31.

Replay Numbers
US Dial-In:	(888) 203-1112
International Dial-In:	(719) 457-0820
Access Code:	6174235

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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 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.

For more information, contact:

Paul Johnson, Vice President, Investor Relations	(612) 215-4535
For news media inquiries only, please call Xcel Energy Media Relations	(612) 215-5300

Xcel Energy website address: www.xcelenergy.com

This information is not given in connection with any

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

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in millions, except per share data)

	Three Months Ended Dec. 31				Twelve Months Ended Dec. 31
	2020		2019		2020		2019
Operating revenues
Electric	$	2,372	$	2,231	$	9,802	$	9,575
Natural gas	554		544		1,636		1,868
Other	21		23		88		86
Total operating revenues	2,947		2,798		11,526		11,529
Operating expenses
Electric fuel and purchased power	901		830		3,512		3,510
Cost of natural gas sold and transported	264		272		689		918
Cost of sales — other	9		12		37		40
Operating and maintenance expenses	616		574		2,324		2,338
Conservation and demand side management expenses	73		73		288		285
Depreciation and amortization	499		446		1,948		1,765
Taxes (other than income taxes)	159		141		612		569
Total operating expenses	2,521		2,348		9,410		9,425
Operating income	426		450		2,116		2,104
Other income (expense), net	—		2		(6)		16
Equity earnings of unconsolidated subsidiaries	11		10		40		39
Allowance for funds used during construction — equity	24		22		115		77
Interest charges and financing costs
Interest charges — includes other financing costs of $7, $7, $28 and $26, respectively	212		195		840		773
Allowance for funds used during construction — debt	(9)		(10)		(42)		(37)
Total interest charges and financing costs	203		185		798		736
Income before income taxes	258		299		1,467		1,500
Income tax (benefit) expense	(30)		7		(6)		128
Net income	$	288	$	292	$	1,473	$	1,372
Weighted average common shares outstanding:
Basic	530		525		527		519
Diluted	532		526		528		520
Earnings per average common share:
Basic	$	0.54	$	0.56	$	2.79	$	2.64
Diluted	0.54		0.56		2.79		2.64

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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.

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 twelve months ended Dec. 31, 2020 and 2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

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Note 1. Earnings Per Share Summary

Xcel Energy’s 2020 earnings were $2.79 per share compared to $2.64 per share in 2019, primarily reflecting higher electric margin (largely due to regulatory outcomes which recover capital investment), higher allowance for funds used during construction (AFUDC) and lower O&M expenses, which offset increased depreciation, interest expense and declining sales primarily due to the impacts of COVID-19.

Summarized diluted EPS for Xcel Energy:

	Three Months Ended Dec. 31				Twelve Months Ended Dec. 31
Diluted Earnings (Loss) Per Share	2020		2019		2020		2019
NSP-Minnesota	$	0.23	$	0.24	$	1.12	$	1.04
PSCo	0.25		0.25		1.11		1.11
SPS	0.10		0.09		0.56		0.51
NSP-Wisconsin	0.04		0.03		0.20		0.15
Equity earnings of unconsolidated subsidiaries	0.01		0.01		0.05		0.05
Regulated utility (a)	0.63		0.62		3.04		2.86
Xcel Energy Inc. and Other	(0.09)		(0.07)		(0.25)		(0.22)
Total (a)	$	0.54	$	0.56	$	2.79	$	2.64

(a) Amounts may not add due to rounding.

NSP-Minnesota — Earnings increased $0.08 per share for 2020, reflecting higher electric margin (riders, wholesale transmission revenue and a sales true-up mechanism, which recovers lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin.

PSCo — Earnings were flat for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and higher natural gas margin, offset by additional depreciation and taxes (other than income taxes).

SPS — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (wholesale transmission revenue and 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 $0.05 per share for 2020, reflecting higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin.

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

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

Diluted Earnings (Loss) Per Share	Three Months Ended Dec. 31		Twelve Months Ended Dec. 31
GAAP and ongoing diluted EPS - 2019	$	0.56	$	2.64
Components of change — 2020 vs. 2019
Higher electric margins (a)	0.10		0.32
Lower ETR (b)	0.05		0.22
Higher AFUDC	—		0.08
Changes in O&M	(0.06)		0.02
Higher depreciation and amortization	(0.07)		(0.26)
Higher interest	(0.02)		(0.10)
Higher taxes (other than income taxes)	(0.03)		(0.06)
Changes in natural gas margins	0.03		(0.01)
Other (net)	(0.02)		(0.06)
GAAP and ongoing diluted EPS — 2020	$	0.54	$	2.79

(a) Change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 and is detailed below. Sales decline excludes weather impact, net of decoupling/sales true-up and reduction in demand revenue is net of sales true-up.

Diluted Earnings (Loss) Per Share	Three Months Ended Dec. 31		Twelve Months Ended Dec. 31
Electric margin (excluding reductions in sales and demand)	$	0.11	$	0.41
Reductions in sales and demand	(0.01)		(0.09)
Higher electric margins	$	0.10	$	0.32

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

ROE for Xcel Energy and its utility subsidiaries:

2020	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Operating Companies		Xcel Energy
GAAP and ongoing ROE	9.20	%	8.06	%	9.54	%	10.52	%	8.87	%	10.59	%

2019	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Operating Companies		Xcel Energy
GAAP and ongoing ROE	9.31	%	8.69	%	9.71	%	8.27	%	9.06	%	10.78	%

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 to the extent there is not a decoupling or sales true-up mechanism in the state.

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.

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

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
	2020 vs. Normal		2019 vs. Normal		2020 vs. 2019		2020 vs. Normal		2019 vs. Normal		2020 vs. 2019
HDD	(3.6)	%	9.9	%	(12.1)	%	(3.1)	%	10.4	%	(12.0)	%
CDD	n/a		n/a		n/a		22.2		5.4		24.8
THI	n/a		n/a		n/a		6.3		(8.8)		18.2

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

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
	2020 vs. Normal		2019 vs. Normal		2020 vs. 2019		2020 vs. Normal		2019 vs. Normal		2020 vs. 2019
Retail electric	$	(0.005)	$	0.005	$	(0.010)	$	0.090	$	0.040	$	0.050
Decoupling and sales true-up	0.003		(0.001)		0.004		(0.041)		—		(0.041)
Total (excluding decoupling)	$	(0.002)	$	0.004	$	(0.006)	$	0.049	$	0.040	$	0.009
Firm natural gas	(0.006)		0.007		(0.013)		(0.011)		0.027		(0.038)
Total (adjusted for recovery from decoupling)	$	(0.008)	$	0.011	$	(0.019)	$	0.038	$	0.067	$	(0.029)

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

	Three Months Ended Dec. 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual (a)
Electric residential	2.4	%	3.1	%	(0.9)	%	1.0	%	2.1	%
Electric C&I	(4.0)		(6.0)		(3.1)		(1.7)		(4.3)
Total retail electric sales	(2.2)		(3.3)		(2.7)		(0.9)		(2.6)
Firm natural gas sales	(5.9)		(6.2)		n/a		1.1		(5.6)

	Three Months Ended Dec. 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized (a)
Electric residential	4.7	%	4.7	%	0.2	%	2.3	%	3.9	%
Electric C&I	(3.8)		(5.7)		(3.1)		(1.4)		(4.1)
Total retail electric sales	(1.4)		(2.6)		(2.6)		(0.3)		(2.0)
Firm natural gas sales	5.0		1.4		n/a		8.1		4.1

	Twelve Months Ended Dec. 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual (a)
Electric residential	5.8	%	5.0	%	3.6	%	2.4	%	4.9	%
Electric C&I	(4.1)		(7.0)		(3.3)		(4.6)		(5.0)
Total retail electric sales	(1.1)		(3.4)		(2.2)		(2.6)		(2.3)
Firm natural gas sales	(6.8)		(8.3)		n/a		(6.4)		(7.2)

	Twelve Months Ended Dec. 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized (a)
Electric residential	3.8	%	3.7	%	1.6	%	2.6	%	3.3	%
Electric C&I	(4.5)		(7.0)		(3.4)		(4.8)		(5.2)
Total retail electric sales	(1.9)		(3.8)		(2.6)		(2.7)		(2.8)
Firm natural gas sales	0.5		1.9		n/a		5.1		1.3

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	Twelve Months Ended Dec. 31 (Leap Year Adjusted)
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized (a)
Electric residential	3.6	%	3.4	%	1.3	%	2.3	%	3.1	%
Electric C&I	(4.8)		(7.3)		(3.7)		(5.0)		(5.4)
Total retail electric sales	(2.2)		(4.1)		(2.9)		(2.9)		(3.1)
Firm natural gas sales	0.1		1.4		n/a		4.6		0.7

(a) Higher residential sales and lower commercial and industrial (C&I) sales were primarily attributable to COVID-19. The increase in residential sales was partially driven by more customers working from home.

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

•PSCo — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the manufacturing and service industries, partially offset by an increase in the energy sector.

•NSP-Minnesota — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy, manufacturing and services sectors.

•SPS — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors.

•NSP-Wisconsin — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors.

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

•Higher natural gas sales reflect an increase in the number of customers combined with higher residential customer use, partially offset by lower C&I customer use.

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 fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense).

Electric revenues and margin:

	Three Months Ended Dec. 31				Twelve Months Ended Dec. 31
(Millions of Dollars)	2020		2019		2020		2019
Electric revenues	$	2,372	$	2,231	$	9,802	$	9,575
Electric fuel and purchased power	(901)		(830)		(3,512)		(3,510)
Electric margin	$	1,471	$	1,401	$	6,290	$	6,065

Change in electric margin:

(Millions of Dollars)	Three Months Ended Dec. 31, 2020 vs. 2019		Twelve Months Ended Dec. 31, 2020 vs. 2019
Regulatory rate outcomes (Colorado, Wisconsin, Texas and New Mexico) (a)	$	52	$	209
Non-fuel riders	31		74
Wholesale transmission revenue (net)	24		59
MEC purchased capacity costs	—		35
Conservation incentive	12		13
2019 tax reform customer credits - Wisconsin (offset in income tax)	10		7
Estimated impact of weather (net of decoupling / sales true-up)	(5)		7
PTCs flowed back to customers (offset by lower ETR)	(38)		(119)
Sales and demand (b)	(10)		(66)
Other (net)	(6)		6
Total increase in electric margin	$	70	$	225

(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.

(b) Sales excludes weather impact, net of decoupling/sales true-up, and demand revenue is net of sales true-up.

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

Natural gas revenues and margin:

	Three Months Ended Dec. 31				Twelve Months Ended Dec. 31
(Millions of Dollars)	2020		2019		2020		2019
Natural gas revenues	$	554	$	544	$	1,636	$	1,868
Cost of natural gas sold and transported	(264)		(272)		(689)		(918)
Natural gas margin	$	290	$	272	$	947	$	950

Change in natural gas margin:

(Millions of Dollars)	Three Months Ended Dec. 31, 2020 vs. 2019		Twelve Months Ended Dec. 31, 2020 vs. 2019
Estimated impact of weather	$	(9)	$	(28)
Regulatory rate outcomes (Colorado and Wisconsin)	18		16
Infrastructure and integrity riders	2		8
Retail sales growth	4		2
Other (net)	3		(1)
Total increase (decrease) in natural gas margin	$	18	$	(3)

O&M Expenses — O&M expenses decreased $14 million, or 0.6%, for 2020, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19. Significant changes are as follows:

(Millions of Dollars)	Three Months Ended Dec. 31, 2020 vs. 2019		Twelve Months Ended Dec. 31, 2020 vs. 2019
Distribution	$	(7)	$	(47)
Generation	(4)		(12)
Transmission	1		(10)
Minnesota payment plan credit program	18		18
Information technology	12		14
Employee benefits	11		12
Texas rate case deferral	3		8
Other (net)	8		3
Total increase (decrease) in O&M expenses	$	42	$	(14)

•Distribution declined due to cost mitigation/continuous improvement efforts and timing of maintenance, partially offset by increased storm impacts.

•Generation was lower from timing of maintenance and overhauls at power plants and cost mitigation/continuous improvement efforts, partially offset by an increase in maintenance expenses from wind expansion.

•Transmission declined due to cost mitigation/continuous improvement initiatives.

•Minnesota payment plan credit program represents a commitment to fund customer programs as agreed to in the NSP-Minnesota rate case stay-out.

•Information technology costs increased due to higher spending on network and other infrastructure costs.

•Employee benefits increased due primarily to postretirement costs and other long-term benefits, partially offset by lower deferred compensation expense.

Depreciation and Amortization — Depreciation and amortization increased $183 million, or 10.4%, year-to-date. The increase was primarily driven by the Hale, Cheyenne Ridge, Foxtail, Blazing Star I, Lake Benton, Sagamore, Crowned Ridge, Community Wind North and Jeffers wind facilities going into service, as well as normal system expansion. In addition, new depreciation rates were implemented in Colorado, New Mexico and Texas in 2020, increasing expense.

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $43 million, or 7.6%, year-to-date. The increase was primarily due to higher property taxes in Colorado and Texas (net of deferred amounts).

Other Income (Expense) — Other income (expense) decreased $22 million year-to-date. The decrease was largely due to the performance of rabbi trust investments, primarily offset in O&M expenses.

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AFUDC, Equity and Debt — AFUDC increased $43 million year-to-date. The increase was primarily due to various wind projects under construction.

Interest Charges — Interest charges increased $67 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 — Effective income tax rate:

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
	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)	4.8		4.8		—		4.9		4.9		—
Increases (decreases):
Wind PTCs	(27.7)		(15.0)		(12.7)		(15.7)		(9.4)		(6.3)
Plant regulatory differences (a)	(8.9)		(6.5)		(2.4)		(7.6)		(5.8)		(1.8)
Net operating loss (NOL) carryback	—		—		—		(0.9)		—		(0.9)
Other tax credits, NOL allowances (net) and tax credit allowances	(1.6)		(1.6)		—		(1.2)		(1.7)		0.5
Other (net)	0.8		(0.4)		1.2		(0.9)		(0.5)		(0.4)
Effective income tax rate	(11.6)	%	2.3	%	(13.9)	%	(0.4)	%	8.5	%	(8.9)	%

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

Income taxes decreased $37 million for the fourth quarter. The decrease was primarily driven by an increase in wind PTCs and lower pretax earnings. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income.

Income taxes decreased $134 million year-to-date. The decrease was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences.

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

Xcel Energy’s capital structure:

(Millions of Dollars)	Dec. 31, 2020		Percentage of Total Capitalization		Dec. 31, 2019		Percentage of Total Capitalization
Current portion of long-term debt	$	421	1	%	$	702	2	%
Short-term debt	584		2		595		2
Long-term debt	19,645		56		17,407		54
Total debt	20,650		59		18,704		58
Common equity	14,575		41		13,239		42
Total capitalization	$	35,225	100	%	$	31,943	100	%

Liquidity —As of Jan. 25, 2021, 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	$	7	$	1,257
PSCo	700		295		405		4		409
NSP-Minnesota	500		344		156		1		157
SPS	500		311		189		2		191
NSP-Wisconsin	150		32		118		1		119
Total	$	3,100	$	982	$	2,118	$	15	$	2,133

(a)    Credit facilities expire in June 2024.

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

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Term Loan Agreements — In December 2020, Xcel Energy Inc. repaid its $500 million Term Loan Agreement. In September 2020, Xcel Energy Inc. repaid its $700 million Term Loan Agreement.

Forward Equity Agreements —In November 2020, Xcel Energy settled the forward equity agreement by issuing 11.8 million shares and receiving cash proceeds of $721 million.

Credit Ratings — Access to the capital markets at reasonable terms is partially dependent on credit ratings. The following ratings reflect the views of Moody’s, S&P Global Ratings, and Fitch. The highest credit rating for debt is Aaa/AAA and the lowest investment grade rating is Baa3/BBB-. The highest rating for commercial paper is P-1/A-1/F-1 and the lowest rating is P-3/A-3/F-3. A security rating is not a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries as of Jan. 25, 2021:

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 — The capital forecasts for Xcel Energy for 2021 through 2025 are detailed in the following tables. The base capital forecast has been updated to reflect the Minnesota Commission’s approval of the $750 million wind repowering proposal. In addition, the base capital forecast reflects a change in the timing of completion of a wind project from 2020 to 2021.

	Base Capital Forecast (Millions of Dollars)
By Regulated Utility	2021		2022		2023		2024		2025		Total
PSCo	$	1,700	$	1,835	$	1,750	$	1,695	$	1,655	$	8,635
NSP-Minnesota	1,930		1,785		1,785		1,915		1,890		9,305
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	$	4,475	$	4,745	$	4,710	$	4,870	$	4,700	$	23,500

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

	Base Capital Forecast (Millions of Dollars)
By Function	2021		2022		2023		2024		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	610		255		165		270		—		1,300
Total base capital expenditures	$	4,475	$	4,745	$	4,710	$	4,870	$	4,700	$	23,500

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	Incremental Capital Forecast (Millions of Dollars) (a)
NSP-Minnesota Proposal	2021		2022		2023		2024		2025		Total
Sherco solar	$	30	$	200	$	320	$	—	$	—	$	550
Wind purchased power agreement (PPA) buyout	25		185		—		—		—		210
Total incremental capital	$	55	$	385	$	320	$	—	$	—	$	760

(a) Reflects potential capital investment under the Minnesota Relief and Recovery plan, which will require commission approval. 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 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)
Cash from Operations (a)	$	15,000
Debt issuance (b)	7,490
Equity through the DRIP and Benefit Program	410
Other Equity	600
Base Capital Expenditures 2021-2025	$	23,500
Maturing Debt	$	3,820

(a) Net of dividends and pension funding.

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

The incremental capital is expected to be financed with approximately 50% debt and 50% equity, if approved by the MPUC.

2020 Financing Activity — During 2020, Xcel Energy issued approximately $73 million of equity through the DRIP and benefit programs. In addition, Xcel Energy Inc. and its utility subsidiaries issued the following bonds:

Issuer	Security	Amount (Millions of Dollars)		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 Financing Activities — During 2021, Xcel Energy Inc. and its utility subsidiaries anticipate the following:

•Xcel Energy Inc. — approximately $400 million in debt financing.

•PSCo — approximately $450 million of first mortgage bonds.

•SPS — approximately $200 million of first mortgage bonds.

•NSP-Minnesota — approximately $650 million of first mortgage bonds.

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

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

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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 proposal included the following:

•Repower 651 MW of owned wind projects (capital investment of $750 million) as well as certain wind projects under PPAs.

•Acquire 120 MW repowered wind farm and buy-out of an existing PPA for $210 million.

•Add solar facilities of 460 MW with an incremental investment of $550 million.

•Accelerate certain grid investment.

•Provide $150 million of incremental electric vehicle (EV) rebates.

In December 2020, The MPUC verbally approved the repowering of owned wind projects and 20 MW of wind projects under PPAs. These projects are estimated to save customers approximately $160 million over the next 25 years. The MPUC is expected to address the solar, the PPA wind repowering acquisition and the EV proposal in the second half of 2021.

NSP-Minnesota 2020 Electric Rate Case — In November 2020, NSP-Minnesota filed an electric rate case seeking a $597 million revenue increase over three years with the MPUC. The rate case is based on a requested ROE of 10.2% and a 52.5% equity ratio. NSP-Minnesota also filed a stay-out alternative in which it would withdraw its rate case filing.

In December 2020, the MPUC verbally approved the stay-out alternative petition, which includes the extension of the sales, capital and property tax true-up mechanisms and delays any increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 2022.

Additionally, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related bad debt expense and committed to fund $17.5 million in a Residential Payment Plan Credit Program or other similar customer relief programs, as directed by the MPUC. NSP-Minnesota also agreed to an earnings test in which all earnings above an ROE of 9.06% in 2021 would be refunded to customers.

2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a request with the North Dakota Public Service Commission for an overall increase in annual retail electric revenues of approximately $22 million, or an increase of 10.8%. The request is driven by ongoing investments in carbon-free electrical generation, distribution and transmission infrastructure. The rate filing is based on a 2021 forecast test year and includes a requested ROE of 10.2%, electric rate base of approximately $677 million and an equity ratio of 52.50%. In addition, interim rates, subject to refund, of approximately $16 million were implemented on Jan. 5, 2021.

PSCo 2020 Natural Gas Rate Case — In October 2020, the CPUC approved a comprehensive settlement, resulting in a net rate increase of $77 million. This increase reflects a $94 million increase in base rate revenue, partially offset by $17 million of costs previously recovered through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 (retroactive to November 2020).

PSCo Wildfire Protection Rider —In 2020, PSCo requested to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective in June 2021 and continue through 2025. The Office of Consumer Counsel and CPUC Staff are supportive of the wildfire mitigation program, but oppose rider recovery and instead recommend deferral of certain costs with recovery in a future rate case. A CPUC decision is expected in the second quarter of 2021.

Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025:

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

PSCo Transportation Electrification Plan (TEP) — In January 2021, the CPUC approved PSCo's TEP, which authorizes rider recovery of new electric vehicle utility programs for the residential, commercial, multi-family and public charging sectors. The approval establishes utility-owned charging infrastructure and chargers and amortization of rebates for electric vehicles. The TEP approval authorizes approximately $110 million in spending with flexibility up to approximately $138 million over three years.

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SPS — New Mexico 2021 Electric Rate Case —In January 2021, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $88 million. SPS' net rate increase to New Mexico customers is expected to be approximately $48 million, or 10%, as a result of offsetting fuel cost reductions and PTCs attributable to the Sagamore wind project. A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021.

The request is based on a return on equity of 10.35%, an equity ratio of 54.72%, a retail rate base of approximately $1.9 billion and a historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021.

In addition, the request includes the reduction of approximately 400 MW wholesale peak load in 2021 and changes to depreciation lives of SPS’ Tolk coal-fired power plant (from 2037 to 2032) and the coal handling assets at the Harrington facility (to 2024).

SPS’ base rate request:

(Millions of Dollars)
Sagamore wind project investment	$	38
Other plant investment	40
Allocator changes due to load growth	9
Depreciation rate change (including Tolk)	3
Other, net	(2)
Total rate request	88
Fuel cost reductions and PTCs	(40)
Net rate increase	$	48

Note 5. Coal Plant Closures

Xcel Energy has a goal to reduce carbon emissions 80% by 2030 (over 2005 levels) and ultimately deliver 100% carbon-free electricity to customers by 2050. The following actions were recently announced to support these initiatives:

•A proposal to close the Hayden coal plant in Colorado, retiring Unit 2 by the end of 2027 and Unit 1 in 2028 (totaling 233 MW of capacity for Xcel Energy). Further details on the early closure will be included in an electric resource plan to be filed with the CPUC in March 2021.

•Retire the Craig generating station in Colorado, with Unit 1 closing in 2025 and Unit 2 closing in 2028 (totaling 82 MW of capacity for Xcel Energy).

•Convert the Harrington generating station in Texas (three units with 1,018 MW of capacity) to natural gas by Jan. 1, 2025.

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

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)

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 remainder of the year.

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

•Weather-normalized retail firm natural gas sales are projected to be relatively flat.

•Capital rider revenue is projected to increase $105 million to $115 million (net of PTCs). The change reflects the deferral of advanced grid costs, which were denied rider recovery. PTCs are credited to customers, through capital riders, fuel clause or base rates and results in a reduction to electric margin.

•O&M expenses are projected to be relatively flat.

•Depreciation expense is projected to increase approximately $195 million to $205 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.

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.

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XCEL ENERGY INC. AND SUBSIDIARIES

EARNINGS RELEASE SUMMARY (UNAUDITED)

(amounts in millions, except per share data)

	Three Months Ended Dec. 31
	2020		2019
Operating revenues:
Electric and natural gas	$	2,926	$	2,775
Other	21		23
Total operating revenues	2,947		2,798
Net income	$	288	$	292
Weighted average diluted common shares outstanding	532		526
Components of EPS — Diluted
Regulated utility	$	0.63	$	0.62
Xcel Energy Inc. and other costs	(0.09)		(0.07)
GAAP and ongoing diluted EPS (a)(b)	$	0.54	$	0.56
Book value per share	$	27.40	$	25.17
Cash dividends declared per common share	0.43		0.41

	Twelve Months Ended Dec. 31
	2020		2019
Operating revenues:
Electric and natural gas	$	11,438	$	11,443
Other	88		86
Total operating revenues	11,526		11,529
Net income	$	1,473	$	1,372
Weighted average diluted common shares outstanding	528		520
Components of EPS — Diluted
Regulated utility	$	3.04	$	2.86
Xcel Energy Inc. and other costs	(0.25)		(0.22)
GAAP and ongoing diluted EPS (a)(b)	$	2.79	$	2.64
Book value per share	$	27.60	$	25.45
Cash dividends declared per common share	1.72		1.62

(a) For the three and twelve months ended Dec. 31, 2020 and 2019, there were no adjustments to GAAP earnings.

(b) Amounts may not add due to rounding.

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