Xcel Energy 2019 Year End Earnings Report

• 2019 earnings per share were $2.64 compared with $2.47 per share in 2018.
• Xcel Energy reaffirms 2020 EPS earnings guidance of $2.73 to $2.83 per share.

 

MINNEAPOLIS--(BUSINESS WIRE)--Xcel Energy Inc. (NASDAQ: XEL) today reported 2019 GAAP and ongoing earnings of $1,372 million, or $2.64 per share, compared with $1,261 million, or $2.47 per share in 2018.

Earnings reflect higher electric margins primarily due to non-fuel riders and regulatory rate outcomes, higher natural gas margins and lower O&M expenses, partially offset by lower AFUDC, increased depreciation and interest expenses.

“We delivered strong financial results again in 2019, with earnings at the upper end of our guidance range. Xcel Energy continues to deliver consistent and solid performance, meeting or exceeding earnings guidance for the 15th consecutive year,” said Ben Fowke, chairman, president and CEO of Xcel Energy.

“We are proud of our continued progress in leading the clean energy transition on our path to 80% carbon reductions by 2030 and 100% carbon-free electricity by 2050, all while providing great value for our customers, communities, and shareholders. We took important steps on that journey this past year, completing three major Steel for Fuel wind projects, which contribute to the almost 4,700 megawatts of additional wind expected on our system by 2021. We begin the new year well-positioned to deliver on our financial objectives in 2020 and beyond.”

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:	[phone]
International Dial-In:	[phone]
Conference ID:	8911094

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. 30 through 12:00 p.m. CDT on Feb. 2.

Replay Numbers
US Dial-In:	[phone]
International Dial-In:	[phone]
Access Code:	8911094

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, long-term EPS and dividend growth rate, 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, 2018 and subsequent securities filings, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: 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; ability of subsidiaries 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; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices; costs of potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; fuel costs; and employee work force and third party contractor factors.

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 December 31						Twelve Months Ended December 31
	2019			2018			2019			2018
Operating revenues
Electric	$	2,231		$	2,300		$	9,575		$	9,719
Natural gas	544			558			1,868			1,739
Other	23			22			86			79
Total operating revenues	2,798			2,880			11,529			11,537
Operating expenses
Electric fuel and purchased power	830			947			3,510			3,854
Cost of natural gas sold and transported	272			305			918			843
Cost of sales — other	12			10			40			35
Operating and maintenance expenses	574			624			2,338			2,352
Conservation and demand side management expenses	73			74			285			290
Depreciation and amortization	446			442			1,765			1,642
Taxes (other than income taxes)	141			139			569			556
Total operating expenses	2,348			2,541			9,425			9,572
Operating income	450			339			2,104			1,965
Other income (expense)	2			(7		)	16			(14		)
Equity earnings of unconsolidated subsidiaries	10			10			39			35
Allowance for funds used during construction — equity	22			30			77			108
Interest charges and financing costs
Interest charges — includes other financing costs of $7, $7, $26 and $25, respectively	195			176			773			700
Allowance for funds used during construction — debt	(10		)	(13		)	(37		)	(48		)
Total interest charges and financing costs	185			163			736			652
Income before income taxes	299			209			1,500			1,442
Income taxes	7			(6		)	128			181
Net income	$	292		$	215		$	1,372		$	1,261
Weighted average common shares outstanding:
Basic	525			515			519			511
Diluted	526			515			520			511
Earnings per average common share:
Basic	$	0.56		$	0.42		$	2.64		$	2.47
Diluted	0.56			0.42			2.64			2.47

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 twelve months ended Dec. 31, 2019 and 2018, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

Note 1. Earnings Per Share Summary

The following summarizes diluted EPS for Xcel Energy:

	Three Months Ended December 31						Twelve Months Ended December 31
Diluted Earnings (Loss) Per Share	2019			2018			2019			2018
Public Service Company of Colorado (PSCo)	$	0.25		$	0.17		$	1.11		$	1.08
NSP-Minnesota	0.24			0.17			1.04			0.96
Southwestern Public Service Company (SPS)	0.09			0.08			0.51			0.42
NSP-Wisconsin	0.03			0.04			0.15			0.19
Equity earnings of unconsolidated subsidiaries	0.01			0.01			0.05			0.04
Regulated utility ^(a)	0.62			0.47			2.86			2.69
Xcel Energy Inc. and Other	(0.07		)	(0.05		)	(0.22		)	(0.22		)
Total ^(a)	$	0.56		$	0.42		$	2.64		$	2.47
^(a)Amounts may not add due to rounding.

PSCo — Earnings increased $0.03 per share for 2019, reflecting higher electric margin due primarily to capital riders and increased natural gas margin attributable to capital riders, weather and sales growth, partially offset by lower AFUDC and higher depreciation, interest and O&M.

NSP-Minnesota — Earnings increased $0.08 per share for 2019, reflecting higher electric margin resulting from regulatory rate outcomes and capital riders and lower O&M, partially offset by increased depreciation.

SPS — Earnings increased $0.09 per share for 2019, reflecting higher electric margin attributable to lower capacity costs, regulatory rate outcomes and higher demand revenue and higher AFUDC, partially offset by increased interest and depreciation.

NSP-Wisconsin — Earnings decreased $0.04 per share for 2019, reflecting lower electric margin, primarily related to sales decline and the impact of unfavorable weather, higher depreciation and lower AFUDC.

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

Components significantly contributing to changes in 2019 EPS compared with the same period in 2018:

Diluted Earnings (Loss) Per Share	Three Months Ended December 31			Twelve Months Ended December 31
GAAP and ongoing diluted EPS — 2018	$	0.42		$	2.47
Components of change — 2019 vs. 2018:
Higher electric margins	0.07			0.29
Lower ETR^(a)	0.02			0.15
Higher natural gas margins	0.03			0.08
Lower O&M	0.07			0.02
Higher depreciation and amortization	(0.01		)	(0.18		)
Higher interest	(0.03		)	(0.11		)
Lower AFUDC	(0.02		)	(0.08		)
Other (net)	0.01			—
GAAP and ongoing diluted EPS — 2019	$	0.56		$	2.64
^(a) Includes production tax credits (PTCs) and timing of tax reform regulatory decisions, which are primarily offset in electric margin.

The following summarizes the ROE for Xcel Energy and its utility subsidiaries at Dec. 31:

ROE — 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	%
ROE — 2018	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Operating Companies		Xcel Energy
GAAP and ongoing ROE	9.10	%	8.91	%	9.14	%	10.77	%	9.14	%	10.65	%

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 20-year 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 December 31						Twelve Months Ended December 31
	2019 vs. Normal		2018 vs. Normal		2019 vs. 2018		2019 vs. Normal		2018 vs. Normal		2019 vs. 2018
HDD	9.9	%	6.4	%	2.7	%	10.4	%	2.2	%	6.8	%
CDD	N/A		N/A		N/A		5.4		26.7		(15.5	)
THI	N/A		N/A		N/A		(8.8	)	37.3		(33.2	)

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

	Three Months Ended December 31								Twelve Months Ended December 31
	2019 vs. Normal			2018 vs. Normal			2019 vs. 2018		2019 vs. Normal		2018 vs. Normal			2019 vs. 2018
Retail electric	$	0.005		$	0.004		$	0.001	$	0.040	$	0.114		$	(0.074	)
Firm natural gas	0.007			0.004			0.003		0.027		0.007			0.020
Total (excluding decoupling)	$	0.012		$	0.008		$	0.004	$	0.067	$	0.121		$	(0.054	)
Decoupling – Minnesota	(0.001		)	(0.002		)	0.001		—		(0.051		)	0.051
Total (adjusted for decoupling)	$	0.011		$	0.006		$	0.005	$	0.067	$	0.070		$	(0.003	)

Sales Growth (Decline) — Sales growth (decline) for actual and weather-normalized sales in 2019 compared to the same period in 2018:

	Three Months Ended December 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	1.7	%	0.7	%	2.5	%	0.2	%	1.3	%
Electric commercial and industrial	—		(2.3	)	2.5		(4.4	)	(0.5	)
Total retail electric sales	0.7		(1.5	)	2.5		(3.1	)	—
Firm natural gas sales	8.0		0.3		N/A		(2.5	)	4.9
	Three Months Ended December 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential	0.3	%	0.6	%	4.3	%	1.1	%	1.0	%
Electric commercial and industrial	—		(2.3	)	2.6		(4.3	)	(0.5	)
Total retail electric sales	0.3		(1.5	)	2.9		(2.8	)	—
Firm natural gas sales	2.7		0.5		N/A		0.8		1.9
	Twelve Months Ended December 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	0.1	%	(3.5	)%	0.3	%	(1.8	)%	(1.5	)%
Electric commercial and industrial	(0.6	)	(4.0	)	3.5		(3.2	)	(1.1	)
Total retail electric sales	(0.3	)	(3.9	)	2.8		(2.8	)	(1.2	)
Firm natural gas sales	12.9		3.6		N/A		(2.0	)	8.8
	Twelve Months Ended December 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential	(0.1	)%	0.1	%	1.9	%	1.1	%	0.4	%
Electric commercial and industrial	(0.6	)	(3.0	)	3.8		(2.6	)	(0.5	)
Total retail electric sales	(0.3	)	(2.1	)	3.4		(1.6	)	(0.3	)
Firm natural gas sales	4.1		1.1		N/A		(2.5	)	2.7

Year-to-date weather-normalized electric sales growth (decline)

• PSCo — Residential sales declined due to lower use per customer, partially offset by an increased number of customers. The decline in commercial and industrial (C&I) was mainly due to lower use per customer, primarily led by the food products and service industries, partially offset by growth in the metal mining and fabricated metal and industries. The decrease in customer use was partially offset by an increase in the number of C&I customers.
• NSP-Minnesota — Flat residential sales reflect lower use per customer offset by customer additions. The decline in C&I sales was a result of customer growth being offset by lower use per customer, and certain customers moving to co-generation. Decreased sales to C&I customers were driven by the energy and manufacturing sectors.
• SPS — Residential sales grew largely due to an increase in customers and higher use per customer. C&I sales grew based on higher use per small C&I customer and an overall increase in the number of C&I customers. In addition, the increase in C&I sales was driven by the oil and natural gas industry in the Permian Basin.
• NSP-Wisconsin — Residential sales growth was primarily attributable to customer additions and more use per customer. The decline in C&I sales was largely due to lower use per customer and decreased sales to the frac sand mining, food and manufacturing sectors, which was partially offset by customer additions.

Year-to-date weather-normalized natural gas sales growth

• Overall natural gas sales reflect an increase in the number of customers combined with higher customer use, particularly C&I at PSCo. This was partially offset by a decline in C&I sales at NSP-Wisconsin, driven by the frac sand mining industry.

Electric Margin — Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium used in the generation of electricity. 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 in a particular period.

Electric revenues and margin:

	Three Months Ended December 31						Twelve Months Ended December 31
(Millions of Dollars)	2019			2018			2019			2018
Electric revenues	$	2,231		$	2,300		$	9,575		$	9,719
Electric fuel and purchased power	(830		)	(947		)	(3,510		)	(3,854		)
Electric margin	$	1,401		$	1,353		$	6,065		$	5,865

Changes in electric margin:

	Three Months			Twelve Months
	Ended Dec. 31,			Ended Dec. 31,
(Millions of Dollars)	2019 vs. 2018			2019 vs. 2018
Non-fuel riders ^(a)	$	26		$	107
Regulatory rate outcomes (Minnesota, New Mexico, North and South Dakota)	16			95
Implementation of lease accounting standard (offset in interest expense and amortization)	5			22
Purchased capacity costs	1			22
Demand revenue	9			20
Wholesale transmission revenue (net)	(11		)	11
Timing of tax reform regulatory decisions (offset in income tax and amortization)	(15		)	(37		)
Estimated impact of weather (net of Minnesota decoupling)	1			(25		)
Firm wholesale generation	(6		)	(20		)
Sales declines (excluding weather impact)	—			(18		)
Other (net)	22			23
Total increase in electric margin	$	48		$	200
^(a) Includes approximately $11 million and $60 million, respectively, of additional PTC benefit (grossed-up for tax) as compared to the same periods in 2018, which are credited to customers through various regulatory mechanisms.

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 December 31						Twelve Months Ended December 31
(Millions of Dollars)	2019			2018			2019			2018
Natural gas revenues	$	544		$	558		$	1,868		$	1,739
Cost of natural gas sold and transported	(272		)	(305		)	(918		)	(843		)
Natural gas margin	$	272		$	253		$	950		$	896

Changes in natural gas margin:

	Three Months		Twelve Months
	Ended Dec. 31,		Ended Dec. 31,
(Millions of Dollars)	2019 vs. 2018		2019 vs. 2018
Infrastructure and integrity riders	$	8	$	19
Estimated impact of weather	2		14
Transport sales	4		7
Retail sales growth	2		7
Other (net)	3		7
Total increase in natural gas margin	$	19	$	54

O&M Expenses — O&M expenses decreased $14 million, or 0.6%, for 2019. Significant changes are summarized below:

	Three Months			Twelve Months
	Ended Dec. 31,			Ended Dec. 31,
(Millions of Dollars)	2019 vs. 2018			2019 vs. 2018
Plant generation	$	(23	)	$	(20	)
Nuclear plant operations and amortization	(4		)	(8		)
Transmission	(7		)	(7		)
Distribution	(7		)	16
Other (net)	(9		)	5
Total decrease in O&M expenses	$	(50	)	$	(14	)

• Plant generation, transmission and distribution costs were lower due to timing of maintenance activities;
• Nuclear plant operations and amortization were lower largely reflecting improved operating efficiencies and reduced refueling outage costs; and
• Distribution expenses in 2019 were higher than 2018 due to storms, labor and overtime incurred primarily in the first six months of 2019.

Depreciation and Amortization — Depreciation and amortization increased $4 million, or 0.9%, for the fourth quarter of 2019 and $123 million, or 7.5%, for 2019. Increase was primarily driven by capital investment including the Rush Creek, Hale, Foxtail and Lake Benton wind farms going into service, natural gas and distribution/transmission replacements, and various software solutions. These increases were partially offset by lower levels of accelerated amortization of PSCo’s prepaid pension asset.

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $2 million, or 1.4%, for the fourth quarter of 2019 and $13 million, or 2.3%, for 2019. Increase was primarily due to higher property taxes in Colorado and Minnesota (net of deferred amounts).

AFUDC, Equity and Debt — AFUDC decreased $11 million for the fourth quarter of 2019 and $42 million for 2019. Decrease was primarily due to the Rush Creek wind project being placed in-service in 2018, partially offset by the Hale wind project, which went into service in June 2019, and other capital investments.

Interest Charges — Interest charges increased $19 million, or 10.8%, for the fourth quarter of 2019 and $73 million, or 10.4%, for 2019. Increase was primarily due to higher debt levels to fund capital investments, changes in short-term interest rates and implementation of lease accounting standard (offset in electric margin).

Income Taxes — Income taxes increased $13 million for the fourth quarter of 2019. The increase was primarily driven by higher pretax earnings and a reduction in excess utility nonplant deferred tax amortization. These were partially offset by an increase in wind PTCs. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was 2.3% for the fourth quarter of 2019 compared with (2.9%) for 2018.

Income taxes decreased $53 million for 2019, primarily driven by an increase in wind PTCs. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. These were partially offset by higher pretax earnings in 2019 and investment tax credits in 2018. The ETR was 8.5% for 2019 compared with 12.6% in 2018.

Additional details provided below:

	Three Months Ended December 31						Twelve Months Ended December 31
	2019		2018		2019 vs 2018		2019		2018		2019 vs 2018
Federal statutory rate	21.0	%	21.0	%	—	%	21.0	%	21.0	%	—	%
State tax (net of federal tax effect)	4.8		5.0		(0.2	)	4.9		5.0		(0.1	)
(Decreases) increases:
Wind PTCs	(15.0	)	(10.5	)	(4.5	)	(9.4	)	(5.2	)	(4.2	)
Plant regulatory differences ^(a)	(6.5	)	(11.5	)	5.0		(5.8	)	(6.2	)	0.4
Other tax credits and NOL allowances (net)	(1.6	)	(2.9	)	1.3		(1.7	)	(1.7	)	—
Amortization of excess utility nonplant deferred taxes	(0.1	)	(5.5	)	5.4		(0.1	)	(0.7	)	0.6
Other (net)	(0.3	)	1.5		(1.8	)	(0.4	)	0.4		(0.8	)
Effective income tax rate	2.3	%	(2.9	)%	5.2	%	8.5	%	12.6	%	(4.1	)%
^(a) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method and the timing of regulatory decisions regarding the return of excess deferred taxes. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.

Note 3. Xcel Energy Capital Structure, Financing and Credit Ratings

Following is the capital structure of Xcel Energy:

			Percentage of Total				Percentage of Total
(Millions of Dollars)	Dec. 31, 2019		Capitalization		Dec. 31, 2018		Capitalization
Current portion of long-term debt	$	702	2	%	$	406	1	%
Short-term debt	595		2		1,038		4
Long-term debt	17,407		54		15,803		54
Total debt	18,704		58		17,247		59
Common equity	13,239		42		12,222		41
Total capitalization	$	31,943	100	%	$	29,469	100	%

Credit Facilities — As of Jan. 27, 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	$	565	$	685	$	—	$	685
PSCo	700		239		461		1		462
NSP-Minnesota	500		134		366		1		367
SPS	500		61		439		1		440
NSP-Wisconsin	150		95		55		—		55
Total	$	3,100	$	1,094	$	2,006	$	3	$	2,009
^(a)Credit facilities expire in June 2024.
^(b)Includes outstanding commercial paper and letters of credit.

Term Loan Agreement — In December 2019, Xcel Energy Inc. entered into a $500 million 364-Day Term Loan Agreement to pay down borrowings and terminate the expiring $500 million 364-Day Term Loan Agreement.

As of Dec. 31, 2019, Xcel Energy Inc.’s term loan borrowings were as follows:

(Millions of Dollars)	Limit		Amount Used		Available
Xcel Energy Inc.	$	500	$	500	$	—

Bilateral Credit Agreement — In March 2019, NSP-Minnesota entered into a one-year uncommitted bilateral credit agreement. The credit agreement is limited in use to support letters of credit.

As of Dec. 31, 2019, NSP-Minnesota’s outstanding letters of credit were as follows:

(Millions of Dollars)	Limit		Amount Outstanding		Available
NSP-Minnesota	$	75	$	22	$	53

Forward Equity Agreements — In 2018, Xcel Energy entered into a forward equity agreement. In August 2019, Xcel Energy settled the forward equity agreement by delivering 9.4 million shares in exchange for $453 million.

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 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. In May 2019, Fitch revised its criteria for assigning short-term ratings and designated SPS’ short-term credit ratings (used for commercial paper) under criteria observation for a potential downgrade. In October 2019, Fitch removed SPS’ short-term credit ratings (used for commercial paper) from under criteria observation and affirmed SPS’ previous short-term rating of F2.

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.

As of Jan 27, 2020, the following represents the credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries:

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

2019 Debt Financing — During 2019, Xcel Energy Inc. and its utility subsidiaries issued the following debt securities:

		Amount
Issuer	Security	(in millions)		Status	Tenor	Coupon
PSCo	First Mortgage Bonds	$	400	Completed	30 Year	4.05	%
Xcel Energy Inc.	Senior Unsecured Bonds	130		Completed	9 Year	4.00
SPS	First Mortgage Green Bonds	300		Completed	30 Year	3.75
PSCo	First Mortgage Green Bonds	550		Completed	30 Year	3.20
NSP-Minnesota	First Mortgage Green Bonds	600		Completed	30 Year	2.90
Xcel Energy Inc.	Senior Unsecured Bonds	500		Completed	10 Year	2.60
Xcel Energy Inc.	Senior Unsecured Bonds	500		Completed	30 Year	3.50

2020 Planned Debt Financing — During 2020, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:

• Xcel Energy Inc. — approximately $700 million of senior unsecured bonds;
• NSP-Minnesota — approximately $550 million of first mortgage bonds;
• NSP-Wisconsin — approximately $100 million of first mortgage bonds;
• PSCo — approximately $750 million of first mortgage bonds; and
• SPS — approximately $300 million of first mortgage bonds.

Xcel Energy Inc. plans to issue approximately $75 to $80 million of equity through the Dividend Reinvestment and Stock Purchase Program and benefit programs.

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 Electric Rate Case and Stay-out Petition — In November 2019, Northern States Power Company-Minnesota (NSP-Minnesota), a Minnesota corporation, and a wholly owned subsidiary of Xcel Energy Inc. (Xcel Energy), filed a three-year electric rate case with the Minnesota Public Utilities Commission (MPUC). The proposed electric rates reflect a three-year increase in revenues of approximately $201.4 million in 2020, with subsequent incremental increases of $146.4 million in 2021 and $118.3 million in 2022. The rate case was based on a requested ROE of 10.2%, a 52.5% equity ratio, an average electric rate base of $9.0 billion for 2020, $9.3 billion for 2021 and $9.8 billion for 2022. In addition, NSP-Minnesota requested interim rates of $122.0 million to be implemented in January 2020 and an incremental $144.0 million to be implemented in January 2021.

In December 2019, the MPUC approved NSP-Minnesota’s stay-out petition, which includes the extension of the sales, capital and property tax true-up mechanisms and delay of any increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 2021.

Mankato Energy Center (MEC) Acquisition — In November 2018, NSP-Minnesota agreed to purchase MEC, a 760 MW natural gas combined cycle facility, for approximately $650 million from Southern Power Company (a subsidiary of Southern Company).

In September 2019, the MPUC denied NSP-Minnesota's request to purchase MEC as a rate base asset. In January 2020, the MPUC approved Xcel Energy’s plan to acquire MEC as a non-regulated investment and step into the terms of the existing PPAs with NSP-Minnesota. A newly formed non-regulated subsidiary of Xcel Energy completed the transaction to purchase MEC on Jan. 17, 2020.

Jeffers Wind and Community Wind North Repowering Acquisition — In October 2019, the MPUC approved NSP-Minnesota’s request to acquire the Jeffers Wind and Community Wind North wind facilities from Longroad Energy. The wind farms will have approximately 70 MW of capacity after being repowered. The repowering is expected to be completed by December 2020, at which time NSP-Minnesota anticipates finalizing the acquisition and to qualify for the full PTC. The $135 million asset acquisition is projected to provide customer savings of approximately $7 million over the life of the facilities.

NSP-Minnesota — Mower Wind Facility — In August 2019, NSP-Minnesota filed a petition with the MPUC to acquire the Mower wind facility from affiliates of NextEra Energy, Inc. for an undisclosed amount. The Mower facility is currently contracted under a PPA with NSP-Minnesota through 2026. Mower is expected to continue to have approximately 99 MW of capacity following a planned repowering. The acquisition would occur after repowering, which is expected to be complete in 2020 and qualify for 100% of the PTC.

NSP-Minnesota will need approval from both the MPUC and FERC to complete the transaction. The Department of Commerce filed comments in opposition due to modeling concerns, which we are working to address. NSP-Minnesota anticipates an MPUC decision in the second quarter of 2020. NSP-Minnesota anticipates receiving FERC approval in the third quarter of 2020.

PSCo — Colorado 2019 Electric Rate Case — In October 2019, PSCo filed rebuttal testimony requesting net rate increase of $108 million. This is based on a $353 million increase, offset by $245 million of previously authorized costs currently recovered through various rider mechanisms. The request was based on a ROE of 10.20%, an equity ratio of 55.61% and a current test year, which includes certain forecasted plant additions through December 2019.

In December 2019, the Colorado Public Utilities Commission (CPUC) held deliberations and approved a current test year ended Aug. 31, 2019, a 9.3% ROE, an equity ratio of 55.61%, the implementation of decoupling in 2020 and other items. This resulted in an estimated $42 million net base rate revenue increase, pending the CPUC’s written decision. Final rates are expected to be implemented in February 2020.

SPS — New Mexico 2019 Electric Rate Case — In July 2019, SPS filed an electric rate case with the New Mexico Public Regulation Commission (NMPRC) seeking an increase in retail electric base rates of approximately $51 million. The rate request is based on a ROE of 10.35%, an equity ratio of 54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. In December 2019, SPS revised its base rate increase request to approximately $47 million, based on a ROE of 10.10% and updated information. The request also included an increase of $14.6 million for accelerated depreciation including the early retirement of the Tolk Coal Plant in 2032.

On Jan. 13, 2020, SPS and various parties filed an uncontested comprehensive stipulation, which includes the following terms:

• A base rate revenue increase of $31 million;
• A ROE of 9.45%;
• An equity ratio of 54.77%; and
• An acceleration of depreciation on the Tolk Coal Plant to reflect early retirement in 2037, which results in a total increase in depreciation expense of $8 million. The Signatories will not oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’s next base rate case.

Hearings are scheduled for Feb. 17-21, 2020 with a NMPRC decision later in the year. SPS anticipates final rates will go into effect in the second or third quarter of 2020.

SPS — Texas 2019 Electric Rate Case — In August 2019, SPS filed an electric rate case with the Public Utility Commission of Texas (PUCT) seeking an increase in retail electric base rates of approximately $141 million. The filing is based on a ROE of 10.35%, a 54.65% equity ratio, a rate base of approximately $2.6 billion and historic test year that ended June 30, 2019. In September 2019, SPS filed an update to the electric rate case and revised its requested increase to approximately $136 million.

The following table summarizes SPS’ base rate increase request:

Revenue Request (Millions of Dollars)
Hale Wind Farm	$	62
Capital investments	47
Depreciation rate change (including Tolk)	34
Cost of capital	10
Expiring purchased power contracts	(28		)
Other, net	11
New revenue request	$	136

The procedural schedule is as follows:

• Intervenor testimony — Feb. 10, 2020
• Staff testimony — Feb. 18, 2020
• Rebuttal testimony — March 11, 2020
• Public hearing begins — March 30, 2020
• Final order deadline — Sept. 7, 2020

The final rates are expected to be made effective relating back to Sept. 12, 2019. SPS expects a decision from the PUCT in the third quarter of 2020.

Note 5. Xcel Energy Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2020 Earnings Guidance — Xcel Energy’s 2020 GAAP and ongoing earnings guidance is a range of $2.73 to $2.83 per share.^(a)

Key assumptions as compared with projected 2019 levels unless noted:

• Constructive outcomes in all rate case and regulatory proceedings.
• Normal weather patterns.
• Weather-normalized retail electric sales are projected to increase ~1%, including impact of leap year.
• Weather-normalized retail firm natural gas sales are projected to increase ~1%, including impact of leap year.
• Capital rider revenue is projected to increase $45 million to $55 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% to 2%.
• Depreciation expense is projected to increase approximately $160 million to $170 million.
• Property taxes are projected to increase approximately $35 million to $45 million.
• Interest expense (net of AFUDC - debt) is projected to increase $50 million to $60 million.
• AFUDC - equity is projected to increase approximately $10 million to $20 million.
• The ETR is projected to be approximately 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.

^(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 2019 base of $2.60 per share, which represents the mid-point of the original 2019 guidance range of $2.55 to $2.65 per share;
• Deliver annual dividend increases of 5% to 7%;
• Target a dividend payout ratio of 60% to 70%; and
• 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 December 31
	2019			2018
Operating revenues:
Electric and natural gas	$	2,775		$	2,858
Other	23			22
Total operating revenues	2,798			2,880
Net income	$	292		$	215
Weighted average diluted common shares outstanding	526			515
Components of EPS — Diluted
Regulated utility	$	0.62		$	0.47
Xcel Energy Inc. and other costs	(0.07		)	(0.05		)
GAAP and ongoing diluted EPS ^(a)	$	0.56		$	0.42
Cash dividends declared per common share	$	0.41		$	0.38
	Twelve Months Ended December 31
	2019			2018
Operating revenues:
Electric and natural gas	$	11,443		$	11,458
Other	86			79
Total operating revenues	11,529			11,537
Net income	$	1,372		$	1,261
Weighted average diluted common shares outstanding	520			511
Components of EPS — Diluted
Regulated utility	$	2.86		$	2.69
Xcel Energy Inc. and other costs	(0.22		)	(0.22		)
GAAP and ongoing diluted EPS ^(a)	$	2.64		$	2.47
Book value per share	$	25.45		$	23.77
Cash dividends declared per common share	1.62			1.52
^(a)Amounts may not add due to rounding.