Xcel Energy Third Quarter 2019 Earnings Report

Xcel Energy Inc. (NASDAQ: XEL) today reported 2019 third quarter GAAP and ongoing earnings of $527 million, or $1.01 per share, compared with $491 million, or $0.96 per share in the same period in 2018.

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

“Xcel Energy achieved solid quarterly results and as a result we have narrowed our expected earnings to the upper half of our 2019 guidance range. In addition we have issued 2020 earnings guidance of $2.73 to $2.83 per share, which is consistent with our 5-7% growth objective,” said Ben Fowke, chairman, president and CEO of Xcel Energy.

“We have planned capital investments of $22 billion in the next five years to continue our clean energy transition, expand our renewable portfolio and enhance and protect service reliability. These investments will deliver economic and environmental benefits for our shareholders, customers and stakeholders while supporting our drive to achieve an 80 percent reduction in carbon emissions 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:				(720) 543-0214
International Dial-In:				(400) 120-8590
Conference ID:				8800386

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. 24 through 12:00 p.m. CDT on Oct. 27.

Replay Numbers
US Dial-In:				(719) 457-0820
International Dial-In:				(888) 203-1112
Access Code:				8121013

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 2019 and 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 Sept. 30								Nine Months Ended Sept. 30
		2019				2018				2019				2018
Operating revenues
Electric		$	2,771			$	2,802			$	7,345			$	7,419
Natural gas		222				227				1,324				1,181
Other		20				19				62				57
Total operating revenues		3,013				3,048				8,731				8,657
Operating expenses
Electric fuel and purchased power		952				1,040				2,679				2,907
Cost of natural gas sold and transported		55				58				646				537
Cost of sales — other		9				9				28				26
Operating and maintenance expenses		580				593				1,764				1,729
Conservation and demand side management expenses		75				77				212				216
Depreciation and amortization		447				440				1,319				1,199
Taxes (other than income taxes)		137				135				429				417
Total operating expenses		2,255				2,352				7,077				7,031
Operating income		758				696				1,654				1,626
Other income (expense)		8				(7		)		14				(8		)
Equity earnings of unconsolidated subsidiaries		10				9				29				25
Allowance for funds used during construction — equity		15				30				55				79
Interest charges and financing costs
Interest charges — includes other financing costs of $6, $6, $19 and $18, respectively		199				177				578				523
Allowance for funds used during construction — debt		(7		)		(13		)		(27		)		(35		)
Total interest charges and financing costs		192				164				551				488
Income before income taxes		599				564				1,201				1,234
Income taxes		72				73				121				187
Net income		$	527			$	491			$	1,080			$	1,047
Weighted average common shares outstanding:
Basic		519				510				517				510
Diluted		521				511				518				510
Earnings per average common share:
Basic		$	1.02			$	0.96			$	2.09			$	2.05
Diluted		1.01				0.96				2.08				2.05

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 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.

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, 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 Sept. 30								Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share		2019				2018				2019				2018
Public Service Company of Colorado (PSCo)		$	0.39			$	0.41			$	0.86			$	0.91
NSP-Minnesota		0.40				0.39				0.81				0.79
Southwestern Public Service Company (SPS)		0.20				0.16				0.42				0.34
NSP-Wisconsin		0.06				0.06				0.12				0.15
Equity earnings of unconsolidated subsidiaries		0.01				0.01				0.04				0.03
Regulated utility (a)		1.06				1.03				2.24				2.22
Xcel Energy Inc. and Other		(0.05		)		(0.07		)		(0.16		)		(0.17		)
Total (a)		$	1.01			$	0.96			$	2.08			$	2.05

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

PSCo — Earnings decreased $0.02 per share for the third quarter of 2019 and $0.05 per share year-to-date. The decrease in year-to-date earnings was driven by higher depreciation, O&M, interest expense and lower allowance for funds used during construction (AFUDC), which offsets higher natural gas and electric margin. Changes in depreciation and AFUDC are primarily driven by the Rush Creek wind project that was placed in service in 2018.

NSP-Minnesota — Earnings increased $0.01 per share for the third quarter of 2019 and $0.02 per share year-to-date. Year-to-date results reflect higher electric margin driven by regulatory rate outcomes, partially offset by the negative impact of weather, unfavorable sales and increased depreciation.

SPS — Earnings increased $0.04 for the third quarter of 2019 and $0.08 per share year-to-date. Year-to-date results reflect higher electric margin attributable to regulatory rate outcomes and sales growth despite unfavorable weather. Higher electric margin and AFUDC associated with the Hale wind project were partially offset by increased depreciation, O&M and interest expenses.

NSP-Wisconsin — Earnings were flat for the third quarter of 2019 and decreased $0.03 per share year-to-date. Year-to-date results reflect 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:

		Three Months				Nine Months
Diluted Earnings (Loss) Per Share		Ended Sept. 30				Ended Sept. 30
GAAP and ongoing diluted EPS — 2018		$	0.96			$	2.05
Components of change — 2019 vs. 2018:
Higher electric margins		0.08				0.22
Lower ETR (a)		0.03				0.12
Higher natural gas margins		—				0.05
Higher depreciation and amortization		(0.01		)		(0.17		)
Higher interest charges		(0.03		)		(0.08		)
Lower AFUDC		(0.04		)		(0.06		)
Changes in O&M		0.02				(0.05		)
GAAP and ongoing diluted EPS — 2019		$	1.01			$	2.08

^(a) Includes production tax credits (PTCs) and timing of tax reform regulatory decisions, 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 and the amount of natural gas or electricity historically used per degree of temperature. 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 Sept. 30									Nine Months Ended Sept. 30
	2019 vs.			2018 vs.			2019 vs.			2019 vs.			2018 vs.			2019 vs.
	Normal			Normal			2018			Normal			Normal			2018
HDD	(64.0	)%		(18.2	)%		(57.0	)%		10.7	%		(0.3	)%		9.4	%
CDD	27.4			14.8			20.9			6.4			27.1			(14.9	)
THI	(2.6	)		18.2			(17.0	)		(8.2	)		38.4			(33.2	)

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

	Three Months Ended Sept. 30												Nine Months Ended Sept. 30
	2019 vs.				2018 vs.				2019 vs.				2019 vs.				2018 vs.				2019 vs.
	Normal				Normal				2018				Normal				Normal				2018
Retail electric	$	0.040			$	0.043			$	(0.003	)		$	0.035			$	0.110			$	(0.075	)
Firm natural gas	(0.001		)		—				(0.001		)		0.021				0.003				0.018
Total (excluding decoupling)	$	0.039			$	0.043			$	(0.004	)		$	0.056			$	0.113			$	(0.057	)
Decoupling – Minnesota	—				(0.018		)		0.018				0.001				(0.050		)		0.051
Total (adjusted for decoupling)	$	0.039			$	0.025			$	0.014			$	0.057			$	0.063			$	(0.006	)

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

		Three Months Ended Sept. 30
		PSCo			NSP-Minnesota			SPS			NSP-Wisconsin			Xcel Energy
Actual
Electric residential		1.7	%		(6.2	)%		5.9	%		(1.8	)%		(1.2	)%
Electric commercial and industrial		(1.6	)		(6.1	)		4.6			(3.6	)		(1.9	)
Total retail electric sales		(0.5	)		(6.1	)		4.7			(3.1	)		(1.7	)
Firm natural gas sales		4.2			1.7			N/A			(10.6	)		2.5
		Three Months Ended Sept. 30
		PSCo			NSP-Minnesota			SPS			NSP-Wisconsin			Xcel Energy
Weather-normalized
Electric residential		(1.1	)%		(1.0	)%		(1.4	)%		1.5	%		(0.9	)%
Electric commercial and industrial		(2.8	)		(4.4	)		3.6			(2.8	)		(1.8	)
Total retail electric sales		(2.2	)		(3.4	)		2.4			(1.7	)		(1.6	)
Firm natural gas sales		6.8			4.0			N/A			(7.9	)		5.1
		Nine Months Ended Sept. 30
		PSCo			NSP-Minnesota			SPS			NSP-Wisconsin			Xcel Energy
Actual
Electric residential		(0.4	)%		(4.8	)%		(0.4	)%		(2.4	)%		(2.4	)%
Electric commercial and industrial		(0.9	)		(4.6	)		3.9			(2.8	)		(1.2	)
Total retail electric sales		(0.7	)		(4.6	)		2.9			(2.7	)		(1.6	)
Firm natural gas sales		15.6			5.3			N/A			(1.7	)		10.9
		Nine Months Ended Sept. 30
		PSCo			NSP-Minnesota			SPS			NSP-Wisconsin			Xcel Energy
Weather-normalized
Electric residential		(0.2	)%		—	%		1.2	%		1.1	%		0.2	%
Electric commercial and industrial		(0.8	)		(3.2	)		4.2			(2.0	)		(0.5	)
Total retail electric sales		(0.5	)		(2.3	)		3.5			(1.2	)		(0.3	)
Firm natural gas sales		4.9			1.3			N/A			(4.1	)		3.2

Year-to-date weather-normalized Electric Sales Growth (Decline)

• PSCo — Residential sales were lower due to a decrease in customer usage, partially offset by customer additions. Commercial and industrial (C&I) decline was due to lower usage in food and service industries, partially offset by growth in metal fabrication and mining industries.

• NSP-Minnesota — Decline in C&I sales was due to expected discrete energy manufacturing customer declines due to newly installed co-generation, which was partially offset by an increase in customers.

• SPS — Residential sales growth was due to customer additions, partially offset by lower use per customer. Higher C&I sales was primarily driven by increase in the oil and natural gas industry in the Permian Basin.

• NSP-Wisconsin — Residential sales growth was attributable to customer additions and increased usage. Decline in C&I sales was due to lower use per customer and decreased sales to the mining, manufacturing and food industries.

Year-to-date weather-normalized Natural Gas Sales Growth

• Natural gas sales reflect an increase in the number of customers combined with higher 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 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 Sept. 30								Nine Months Ended Sept. 30
(Millions of Dollars)		2019				2018				2019				2018
Electric revenues		$	2,771			$	2,802			$	7,345			$	7,419
Electric fuel and purchased power		(952		)		(1,040		)		(2,679		)		(2,907		)
Electric margin		$	1,819			$	1,762			$	4,666			$	4,512

Changes in electric margin:

(Millions of Dollars)		Three Months Ended Sept. 30, 2019 vs. 2018				Nine Months Ended Sept. 30, 2019 vs. 2018
Non-fuel riders (a)		$	25			$	81
Regulatory rate outcomes (Minnesota, New Mexico, North and South Dakota)		32				79
Wholesale transmission revenue (net)		11				22
Purchased capacity costs		6				21
Implementation of lease accounting standard (offset in interest expense and amortization)		5				16
Demand revenue		(1		)		12
Estimated impact of weather (net of Minnesota decoupling)		6				(26		)
Timing of tax reform regulatory decisions (offset in income tax and amortization)		(3		)		(22		)
Sales declines (excluding weather impact and net of sales true-up)		(16		)		(17		)
Firm wholesale generation		(9		)		(14		)
Other (net)		1				2
Total increase in electric margin		$	57			$	154

^(a) Includes approximately $17 million and $50 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 Sept. 30								Nine Months Ended Sept. 30
(Millions of Dollars)		2019				2018				2019				2018
Natural gas revenues		$	222			$	227			$	1,324			$	1,181
Cost of natural gas sold and transported		(55		)		(58		)		(646		)		(537		)
Natural gas margin		$	167			$	169			$	678			$	644

Changes in natural gas margin:

(Millions of Dollars)		Three Months Ended Sept. 30, 2019 vs. 2018				Nine Months Ended Sept. 30, 2019 vs. 2018
Estimated impact of weather		$	—			$	12
Infrastructure and integrity riders		4				11
Retail sales growth		1				5
Retail rate increase (Colorado, partially offset in amortization)		(8		)		4
Transport sales		1				4
Conservation revenue (offset in expenses)		—				(3		)
Other (net)		—				1
Total (decrease) increase in natural gas margin		$	(2	)		$	34

O&M Expenses — O&M expenses decreased $13 million, or 2.2%, for the third quarter of 2019 and increased $35 million, or 2.0%, year-to-date. Significant changes are summarized below:

(Millions of Dollars)		Three Months Ended Sept. 30, 2019 vs. 2018				Nine Months Ended Sept. 30, 2019 vs. 2018
Distribution		$	—			$	23
Business systems		(6		)		5
Plant generation		—				3
Natural gas operations		(3		)		1
Nuclear plant operations and amortization		(4		)		(4		)
Other (net)		—				7
Total (decrease) increase in O&M expenses		$	(13	)		$	35

• Distribution expenses for the nine month comparison were higher due to storms and labor charges incurred during the first half of the year;

• Business Systems costs were higher for the nine month comparison, primarily due to increased customer experience transformation program expenses;

• Natural gas operation expenses for the nine month comparison increased due to pipeline maintenance; and

• Nuclear plant operations and amortization are lower largely reflecting savings initiatives and reduced refueling outage costs.

Depreciation and Amortization — Depreciation and amortization increased $7 million, or 1.6%, for the third quarter of 2019 and $120 million, or 10.0%, year-to-date. Increase was primarily driven by the Rush Creek and Hale wind farms going into service, as well as other capital investments, which was partially offset by accelerated amortization of PSCo’s prepaid pension asset in the third quarter of 2018.

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $2 million, or 1.5%, for the third quarter of 2019 and $12 million, or 2.9%, year-to-date. Increase was primarily due to higher property taxes in Colorado and Minnesota (net of deferred amounts).

AFUDC, Equity and Debt — AFUDC decreased $21 million for the third quarter of 2019 and $32 million year-to-date. 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 $22 million, or 12.4%, for the third quarter of 2019 and $55 million, or 10.5%, year-to-date. 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 decreased $1 million for the third quarter of 2019. Higher pre-tax earnings were offset by an increase in wind PTCs and tax benefit adjustments attributable to the tax return filed for 2018. 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 12.0% for the third quarter of 2019 compared with 12.9% for the same period in 2018, largely due to the adjustments above.

Income taxes decreased $66 million for the first nine months of 2019, primarily driven by additional wind PTCs and lower pre-tax earnings. 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 10.1% for the first nine months of 2019 compared with 15.2% for the same period in 2018, largely due to the adjustments above.

Additional details provided below:

		Three Months Ended Sept. 30									Nine Months Ended Sept. 30
		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)		5.0			5.0			—			5.0			5.0			—
(Decreases) increases:
Wind PTCs		(6.1	)		(2.6	)		(3.5	)		(8.1	)		(4.3	)		(3.8	)
Plant regulatory differences (a)		(5.6	)		(9.4	)		3.8			(5.5	)		(5.2	)		(0.3	)
Other tax credits and allowances (net)		(1.7	)		(1.9	)		0.2			(1.8	)		(1.5	)		(0.3	)
Other (net)		(0.6	)		0.8			(1.4	)		(0.5	)		0.2			(0.7	)
Effective income tax rate		12.0	%		12.9	%		(0.9	)%		10.1	%		15.2	%		(5.1	)%

^(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:

(Millions of Dollars)		Sept. 30, 2019			Percentage of Total Capitalization			Dec. 31, 2018			Percentage of Total Capitalization
Current portion of long-term debt		$	853		3	%		$	406		1	%
Short-term debt		933			3			1,038			4
Long-term debt		16,819			53			15,803			54
Total debt		18,605			59			17,247			59
Common equity		13,141			41			12,222			41
Total capitalization		$	31,746		100	%		$	29,469		100	%

Credit Facilities — As of Oct. 21, 2019, 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		$	379		$	871		$	1		$	872
PSCo		700			9			691			256			947
NSP-Minnesota		500			19			481			110			591
SPS		500			2			498			181			679
NSP-Wisconsin		150			66			84			1			85
Total		$	3,100		$	475		$	2,625		$	549		$	3,174

^(a) Credit facilities expire in June 2024.

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

Term Loan Agreement — In December 2018, Xcel Energy Inc. renewed its $500 million 364-Day Term Loan Agreement. No additional capacity remains as loans borrowed and repaid may not be redrawn.

As of Sept. 30, 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 Sept. 30, 2019, NSP-Minnesota’s outstanding letters of credit were as follows:

(Millions of Dollars)		Limit			Amount Outstanding			Available
NSP-Minnesota		$	75		$	20		$	55

Forward Equity Agreement — In 2018, Xcel Energy entered into a forward equity agreement. On Aug. 29, 2019, Xcel Energy settled the forward equity agreement by delivering 9.4 million shares in exchange for $453 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. 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 Oct. 21, 2019, 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

Capital Expenditures — The estimated base capital expenditures for Xcel Energy for 2020 through 2024 are shown in the table below:

		Base Capital Forecast
By Subsidiary (Millions of Dollars)		2020				2021				2022				2023				2024				2020 - 2024
																						Total
NSP-Minnesota		$	2,025			$	1,580			$	1,670			$	1,800			$	1,845			$	8,920
PSCo		1,415				1,445				1,720				1,565				1,530				7,675
SPS		1,025				530				700				750				800				3,805
NSP-Wisconsin		250				320				345				350				425				1,690
Other (a)		(85		)		(65		)		10				10				10				(120		)
Total capital expenditures		$	4,630			$	3,810			$	4,445			$	4,475			$	4,610			$	21,970
		Base Capital Forecast
By Function (Millions of Dollars)		2020				2021				2022				2023				2024				2020 - 2024
																						Total
Electric distribution		$	885			$	1,140			$	1,415			$	1,470			$	1,350			$	6,260
Electric transmission		625				835				1,295				1,270				1,260				5,285
Electric generation		480				595				580				780				1,000				3,435
Natural gas		520				450				600				560				640				2,770
Other		360				475				555				395				360				2,145
Renewables		1,760				315				—				—				—				2,075
Total capital expenditures		$	4,630			$	3,810			$	4,445			$	4,475			$	4,610			$	21,970

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

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 regulation, and merger, acquisition and divestiture opportunities.

Financing for Capital Expenditures through 2024 — 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. The current estimated financing plans of Xcel Energy for 2020 through 2024 are shown in the table below:

(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations(a)		$	13,905
New Debt(b)		6,665
Equity through the Dividend Reinvestment Program (DRIP) and Benefit Program		400
Other equity		1,000
Base Capital Expenditures 2020-2024		$	21,970
Maturing Debt		$	3,245

^(a) Net of dividends and pension funding.

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

2019 Debt Financing — During 2019, Xcel Energy Inc. plans to issue approximately $75 to $80 million of equity through the Dividend Reinvestment and Stock Purchase Program and benefit programs. In addition, Xcel Energy Inc. and its utility subsidiaries issued or anticipate issuing the following debt securities:

Issuer

Security

Amount (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

1,000

Pending

TBD

TBD

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.

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

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

On Sept. 27, 2019, the Minnesota Public Utilities Commission (MPUC) voted to deny NSP-Minnesota's request to purchase MEC. The MPUC determined there was too much uncertainty regarding estimated customer benefits associated with the transaction without being able to fully review NSP-Minnesota's Resource Plan (filed July 2019).

Xcel Energy plans to acquire MEC as a non-regulated investment and step into the terms of the existing power purchase agreements (PPA) with NSP-Minnesota. Xcel Energy provided Southern Power Company formal contractual notice of transferring the purchase agreement to a newly formed non-regulated subsidiary and submitted acquisition and affiliated interest filings to the Federal Energy Regulatory Commission (FERC) and MPUC, respectively. Approval is anticipated by the end of 2019.

NSP-Minnesota — Jeffers Wind and Community Wind North Repowering Acquisition — In December 2018, NSP-Minnesota filed a request with the MPUC seeking approval to acquire the Jeffers and Community Wind North wind facilities in western Minnesota from Longroad Energy. The wind farms, currently contracted under PPAs with NSP-Minnesota, will have approximately 70 MW of capacity after being repowered. The repowering and acquisition are expected to be complete by December 2020 and qualify for the 100% PTC benefit. The $135 million asset acquisition is projected to provide customer savings of approximately $7 million over the life of the facilities, compared to the amended PPAs. The FERC approved the acquisition in July 2019.

The DOC filed initial comments in support of NSP-Minnesota continuing to contract for the assets under the amended PPAs, but not the acquisition. In reply comments, NSP-Minnesota indicated it would be willing to acquire the wind facilities as a non-regulated investment and step into the terms of the PPAs, similar to MEC. In October, Xcel Energy filed with FERC requesting contingent approval for a non-regulated subsidiary to acquire the facilities, depending on the MPUC decision. The MPUC decision is expected in the fourth quarter of 2019.

NSP-Minnesota — Mower Wind Facility — On Aug. 30, 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 located in southeastern Minnesota and is currently contracted under a PPA with NSP-Minnesota through 2026. Mower will be repowered and continue to have approximately 99 MW of capacity. 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. Timing of approval is uncertain.

NSP-Wisconsin — Rate Case Settlement — In September 2019, the PSCW issued an interim order approving a settlement agreement. The settlement agreement results in no change to base electric rates through Dec. 31, 2021. For the natural gas utility, there would be a $3.2 million (4.6%) decrease to base rates, effective Jan. 1, 2020, and no additional changes to base rates through Dec. 31, 2021. The settlement is based on a return on equity (ROE) of 10.0% and an equity ratio of 52.5%. It also includes an earnings sharing mechanism, which would return to customers 50% of earnings between 10.25% and 10.75% ROE and 100% of earnings equal to or in excess of 10.75% ROE.

PSCo — Colorado 2019 Electric Rate Case — In May 2019, PSCo filed a request with the Colorado Public Utilities Commission (CPUC) seeking a net rate increase of approximately $158 million, or 5.7%. The filing also requests the transfer of $249 million of rider revenue to base rates, which will not impact overall customer bills as the revenue is currently being recovered through various riders. The request is based on a ROE of 10.35%, an equity ratio of 56.46%, a rate base of approximately $8.2 billion, a historic test year ended Dec. 31, 2018 (adjusted for 2019 capital investment) and incorporates the full impact of tax reform.

In October 2019, PSCo filed rebuttal testimony and revised its request seeking a net increase to retail electric base rate revenue of $108.3 million, reflecting a $353.3 million increase offset by $245.0 million of previously authorized costs (currently recovered through various rider mechanisms). The rebuttal includes certain forecasted plant additions through June 2019 based on a 13-month average rate base convention, a ROE of 10.20%, an equity ratio of 55.61% (based on a 13-month average equity ending Aug. 31, 2019) and inclusion of short-term debt in the capital structure and CWIP in rate base.

The procedural schedule is as follows:

• Settlement deadline — Oct. 30, 2019

• Evidentiary hearing — Nov. 4-13, 2019

• A CPUC decision is anticipated in December 2019 with implementation of final rates on Jan. 1, 2020.

In September 2019, the CPUC Staff, FEA, OCC and CEC filed comprehensive answer testimony. Several other parties filed additional testimony.

Recommendations and the estimated impact on PSCo’s filed electric rate request as calculated by the filing parties, but with our estimate of the impact of their recommendations on riders are as follows:

(Millions of Dollars)		Filed base revenue request				Less: Previously authorized costs (existing riders) (b)				Filed net change to revenue (c)
PSCo		$	408			$	249			$	158
CPUC Staff (a)		235				227				8
FEA		246				239				7
OCC (a)		207				216				(9		)
CEC (a)		187				213				(26		)

^(a) Staff, OCC and CEC have incorporated corrections to the filed case of ($4) million identified by PSCo.

^(b) Amounts derived from intervenors’ positions attributable to previously authorized costs (existing riders), impacted by proposed differences in weighted average cost of capital.

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

Positions on PSCo’s filed electric rate request are as follows:

Recommended Position		Staff					FEA					OCC					CEC
ROE		9.00	%				9.20	%				8.80	%				8.90	%
Equity		55.57	%				56.11	%				54.60	%				54.27	%
Test Year		2019 Current			(a)		2018 Historic			(b)		2018 Historic			(c)		2018 Historic			(d)

^(a) Incorporated 13-month average of proposed forecasted plant additions and rejected adjustments for wildfire mitigation improvements.

^(b) Incorporated year-end rate base and rejected proposed forecasted plant additions. Except for the transmission portion, the FEA supported portions of wildfire mitigation improvements and included 2019 distribution capital and O&M in its cost of service amount.

^(c) Incorporated proposed 13-month average rate base while rejecting the proposed forecasted plant additions including amounts requested for AGIS and wildfire mitigation improvements.

^(d) Rejected proposed forecasted plant additions and the majority of the adjustment for wildfire mitigation improvements.

PSCo — Colorado 2019 Steam Rate Case — In May 2019, PSCo filed an unopposed settlement agreement with CPUC Staff and the City of Denver. The settlement reflects a rate increase of $7 million, a ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. In September 2019, the CPUC approved the Settlement Agreement without modification. The first stepped increase went into effect Oct. 1, 2019, with full rates effective Oct. 1, 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 requests an ROE of 10.35%, a 54.65% equity ratio, a rate base of approximately $2.6 billion and is built on a 12 month period 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 established at the end of the rate case are expected to be made effective relating back to Sept. 12, 2019. SPS expects a decision from the PUCT in the second quarter of 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%, a 54.77% equity ratio, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. SPS anticipates final rates will go into effect in the second or third quarter of 2020.

SPS' proposed increase in base rates would be partially mitigated by savings to New Mexico customers achieved through fuel cost reductions and PTCs attributable to wind energy provided by the Hale Wind Farm. SPS’ $51 million requested increase in base rates would be offset by approximately $25 million of savings resulting in a net revenue increase of approximately $26 million, or 5.7%.

The following table summarizes SPS’ base rate increase request:

Revenue Request (Millions of Dollars)
Hale Wind Farm		$	28
Other plant investment		22
Wholesale sales reduction		17
Allocator changes due to load growth		15
Depreciation rate change (including Tolk)		15
Base rate sales growth		(41		)
Other, net		(5		)
New revenue request		$	51

The procedural schedule is as follows:

• Filing of stipulation, if any — Nov. 15, 2019

• Staff and intervenor testimony or testimony in support of a stipulation — Nov. 22, 2019

• Testimony in opposition to a stipulation, if any — Dec. 6, 2019

• Rebuttal testimony — Dec. 20, 2019

• Public hearing begins — Jan. 7, 2020

• End of 9-month suspension — April 30, 2020

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

Xcel Energy 2019 Earnings Guidance — Xcel Energy narrows its 2019 earnings guidance to $2.60 to $2.65 per share from $2.55 to $2.65 per share.^(a)

Key assumptions as compared with 2018 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 be relatively consistent.

• Weather-normalized retail firm natural gas sales are projected to be within a range of 2.0% to 3.0%.

• Capital rider revenue is projected to increase $115 million to $125 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.

• Purchase capacity costs are expected to decline $25 million to $30 million.

• O&M expenses are projected to decrease approximately 1.0% to 2.0%.

• Depreciation expense is projected to increase approximately $135 million to $145 million. Depreciation expense includes $34 million for the amortization of a prepaid pension asset at PSCo, which is tax reform related and will not impact earnings.

• Property taxes are projected to increase approximately $10 million to $20 million.

• Interest expense (net of AFUDC - debt) is projected to increase $80 million to $90 million.

• AFUDC - equity is projected to decrease approximately $20 million to $30 million.

• The ETR is projected to be approximately 8% to 10%. The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not impact net income.

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 2%.

• Depreciation expense is projected to increase approximately $180 million to $190 million, which includes $30 million of nuclear decommission which is expected to be recovered from customers in rate filings.

• Property taxes are projected to increase approximately $25 million to $35 million.

• Interest expense (net of AFUDC - debt) is projected to increase $50 million to $60 million.

• AFUDC - equity is projected to increase approximately $20 million to $30 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 impact 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% 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 Sept. 30
		2019				2018
Operating revenues:
Electric and natural gas		$	2,993			$	3,029
Other		20				19
Total operating revenues		3,013				3,048
Net income		$	527			$	491
Weighted average diluted common shares outstanding		521				511
Components of EPS — Diluted
Regulated utility		$	1.06			$	1.03
Xcel Energy Inc. and other costs		(0.05		)		(0.07		)
GAAP and ongoing diluted EPS		$	1.01			$	0.96
Cash dividends declared per common share		$	0.41			$	0.38
		Nine Months Ended Sept. 30
		2019				2018
Operating revenues:
Electric and natural gas		$	8,669			$	8,600
Other		62				57
Total operating revenues		8,731				8,657
Net income		$	1,080			$	1,047
Weighted average diluted common shares outstanding		518				510
Components of EPS — Diluted
Regulated utility		$	2.24			$	2.22
Xcel Energy Inc. and other costs		(0.16		)		(0.17		)
GAAP and ongoing diluted EPS		$	2.08			$	2.05
Book value per share		$	25.35			$	23.85
Cash dividends declared per common share		1.22				1.14

 

View source version on businesswire.com: https://www.businesswire.com/news/home/20191024005177/en/

Source: Business Wire
(October 24, 2019 - 6:00 AM EDT)

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