Xcel Energy Second Quarter 2019 Earnings Report

• GAAP 2019 second quarter earnings per share were $0.46 compared with $0.52 per share in 2018.

• Xcel Energy reaffirms 2019 earnings guidance of $2.55 to $2.65 per share.

MINNEAPOLIS--(BUSINESS WIRE)--Xcel Energy Inc. (NASDAQ: XEL) today reported 2019 second quarter GAAP and ongoing earnings of $238 million, or $0.46 per share, compared with $265 million, or $0.52 per share in the same period in 2018.

Earnings reflect higher electric and natural gas margins primarily due to non-fuel riders and regulatory rate outcomes, more than offset by 5 cents per share of unfavorable weather, increased depreciation, interest and operating and maintenance expenses.

“Despite the milder than normal weather in the second quarter, Xcel Energy’s year-to-date earnings are on track and we are well-positioned to deliver earnings within our guidance range for the year,” said Ben Fowke, chairman, president and CEO of Xcel Energy.

“I am pleased that we have filed our Upper Midwest Resource Plan, which is another significant step forward in our industry leading drive to reduce carbon emissions while ensuring reliability and affordability,” said Fowke. “This plan achieves an 80% reduction in carbon emissions in the region by 2030, through the early retirement of the remaining coal units in the Upper Midwest, by substantially growing the amount of renewables on our system and adding new firm peaking resources to ensure continued reliability. This plan is a key stepping stone toward the company achieving its vision to provide customers 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:	[phone]
International Dial-In:	[phone]
Conference ID:	8121013

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 Aug. 1 through 12:00 p.m. CDT on Aug. 4.

Replay Numbers
US Dial-In:	[phone]
International Dial-In:	[phone]
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 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 June 30						Six Months Ended June 30
	2019			2018			2019			2018
Operating revenues
Electric	$	2,249		$	2,348		$	4,574		$	4,617
Natural gas	308			292			1,102			954
Other	20			18			42			38
Total operating revenues	2,577			2,658			5,718			5,609
Operating expenses
Electric fuel and purchased power	813			935			1,727			1,867
Cost of natural gas sold and transported	112			104			591			479
Cost of sales — other	10			8			19			17
Operating and maintenance expenses	586			578			1,184			1,135
Conservation and demand side management expenses	65			69			137			139
Depreciation and amortization	439			377			872			760
Taxes (other than income taxes)	142			137			292			282
Total operating expenses	2,167			2,208			4,822			4,679
Operating income	410			450			896			930
Other income (expense)	2			(2		)	6			(1		)
Equity earnings of unconsolidated subsidiaries	9			9			19			16
Allowance for funds used during construction — equity	20			26			40			49
Interest charges and financing costs
Interest charges — includes other financing costs of $6, $6, $13 and $12, respectively	189			175			379			346
Allowance for funds used during construction — debt	(10		)	(11		)	(20		)	(22		)
Total interest charges and financing costs	179			164			359			324
Income before income taxes	262			319			602			670
Income taxes	24			54			49			114
Net income	$	238		$	265		$	553		$	556
Weighted average common shares outstanding:
Basic	516			510			515			509
Diluted	518			510			517			510
Earnings per average common share:
Basic	$	0.46		$	0.52		$	1.07		$	1.09
Diluted	0.46			0.52			1.07			1.09

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 six months ended June 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 June 30						Six Months Ended June 30
Diluted Earnings (Loss) Per Share	2019			2018			2019			2018
Public Service Company of Colorado (PSCo)	$	0.20		$	0.24		$	0.47		$	0.50
NSP-Minnesota	0.19			0.18			0.41			0.40
Southwestern Public Service Company (SPS)	0.11			0.11			0.22			0.18
NSP-Wisconsin	0.02			0.03			0.06			0.09
Equity earnings of unconsolidated subsidiaries	0.01			0.01			0.02			0.02
Regulated utility ^(a)	0.53			0.58			1.18			1.19
Xcel Energy Inc. and other	(0.06		)	(0.06		)	(0.11		)	(0.10		)
Total ^(a)	$	0.46		$	0.52		$	1.07		$	1.09

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

PSCo — Earnings decreased $0.04 per share for the second quarter of 2019 and $0.03 per share year-to-date. The decrease in year-to-date earnings was driven by higher O&M and depreciation partially offset by the timing of gas rates in 2018 and higher gas sales.

NSP-Minnesota — Earnings increased $0.01 per share for the second quarter of 2019 and $0.01 per share year-to-date. The increase in year-to-date earnings primarily reflects higher electric margins driven by rate case outcomes, partially offset by increased depreciation and O&M expenses.

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

NSP-Wisconsin — Earnings decreased $0.01 per share for the second quarter of 2019 and $0.03 per share year-to-date, largely due to unfavorable weather, higher depreciation and O&M expenses.

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			Six Months
Diluted Earnings (Loss) Per Share	Ended June 30			Ended June 30
GAAP and ongoing diluted EPS — 2018	$	0.52		$	1.09
Components of change — 2019 vs. 2018
Higher electric margins	0.03			0.14
Lower ETR ^(a)	0.03			0.10
Higher natural gas margins	0.01			0.05
Higher depreciation and amortization	(0.09		)	(0.16		)
Higher O&M	(0.01		)	(0.07		)
Higher interest charges	(0.02		)	(0.05		)
Higher taxes (other than income taxes)	(0.01		)	(0.01		)
Other (net)	—			(0.02		)
GAAP and ongoing diluted EPS — 2019	$	0.46		$	1.07

^(a) Includes flow back of production tax credits (PTCs) and timing of tax reform regulatory decisions, which are primarily offset in revenue.

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 June 30						Six Months Ended June 30
	2019 vs. Normal		2018 vs. Normal		2019 vs. 2018		2019 vs. Normal		2018 vs. Normal		2019 vs. 2018
HDD	16.9	%	0.1	%	15.0	%	12.8	%	0.3	%	11.0	%
CDD	(45.2	)	59.1		(71.4	)	(45.5	)	59.7		(65.1	)
THI	(26.7	)	108.1		(64.6	)	(26.9	)	107.4		(64.5	)

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

	Three Months Ended June 30									Six Months Ended June 30
	2019 vs. Normal			2018 vs. Normal			2019 vs. 2018			2019 vs. Normal			2018 vs. Normal			2019 vs. 2018
Retail electric	$	(0.024	)	$	0.065		$	(0.089	)	$	(0.005	)	$	0.067		$	(0.072	)
Firm natural gas	0.004			0.002			0.002			0.022			0.003			0.019
Total (excluding decoupling)	$	(0.020	)	$	0.067		$	(0.087	)	$	0.017		$	0.070		$	(0.053	)
Decoupling – Minnesota	0.006			(0.030		)	0.036			0.001			(0.032		)	0.033
Total (adjusted for decoupling)	$	(0.014	)	$	0.037		$	(0.051	)	$	0.018		$	0.038		$	(0.020	)

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

	Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(6.5	)%	(10.7	)%	(13.2	)%	(9.0	)%	(9.4	)%
Electric commercial and industrial	(1.4	)	(6.2	)	2.6		(2.5	)	(2.3	)
Total retail electric sales	(2.9	)	(7.5	)	(0.5	)	(4.2	)	(4.2	)
Firm natural gas sales	19.6		(1.2	)	N/A		(10.7	)	10.5

	Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential	0.3	%	0.8	%	1.9	%	1.7	%	0.8	%
Electric commercial and industrial	0.7		(3.6	)	4.5		(0.6	)	—
Total retail electric sales	0.6		(2.4	)	3.9		—		0.2
Firm natural gas sales	5.3		4.8		N/A		(7.9	)	4.4

	Six Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(1.7	)%	(4.0	)%	(4.2	)%	(2.8	)%	(3.1	)%
Electric commercial and industrial	(0.4	)	(3.7	)	3.4		(2.4	)	(0.8	)
Total retail electric sales	(0.8	)	(3.8	)	1.9		(2.5	)	(1.5	)
Firm natural gas sales	17.1		5.7		N/A		(0.8	)	11.9

	Six Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential	0.3	%	0.5	%	2.8	%	0.9	%	0.8	%
Electric commercial and industrial	0.4		(2.5	)	4.6		(1.6	)	0.2
Total retail electric sales	0.4		(1.6	)	4.1		(0.9	)	0.4
Firm natural gas sales	4.7		1.1		N/A		(3.7	)	3.0

Weather-normalized Electric Sales Growth (Decline)

• PSCo — Higher residential sales growth reflects customer additions, partially offset by lower use per customer. Commercial and industrial (C&I) growth was due to an increase in customers and higher use per customer, predominately from the fabricated metal and metal mining industries.
• NSP-Minnesota — Higher residential sales growth reflects customer additions, partially offset by lower use per customer. Decline in C&I sales was due to lower use per customer (self-generation), which was partially offset by an increase in customers. Decreased sales to C&I customers were driven by the energy and manufacturing sectors.
• SPS — Residential sales grew largely due to higher use per customer and customer additions. Higher C&I sales was primarily due to increased use per customer, driven by the oil and natural gas industry in the Permian Basin.
• NSP-Wisconsin — Residential sales growth was primarily attributable to customer additions and higher use per customer. The decline in C&I sales was due to lower use per customer and decreased sales to the mining, manufacturing and food services sectors, partially offset by customer additions.

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 June 30						Six Months Ended June 30
(Millions of Dollars)	2019			2018			2019			2018
Electric revenues	$	2,249		$	2,348		$	4,574		$	4,617
Electric fuel and purchased power	(813		)	(935		)	(1,727		)	(1,867		)
Electric margin	$	1,436		$	1,413		$	2,847		$	2,750

Changes in electric margin:

	Three Months			Six Months
	Ended June 30,			Ended June 30,
(Millions of Dollars)	2019 vs. 2018			2019 vs. 2018
Non-fuel riders ^(a)	$	21		$	57
Regulatory rate outcomes (Minnesota, New Mexico, North and South Dakota)	19			47
Lower purchased capacity costs	9			15
Demand revenue	11			13
Implementation of lease accounting standard (offset in interest expense and amortization)	5			11
Wholesale transmission revenue (net)	3			11
Estimated impact of weather (net of Minnesota decoupling)	(40		)	(32		)
Timing of tax reform regulatory decisions (offset in income tax)	(6		)	(19		)
Other (net)	1			(6		)
Total increase in electric margin	$	23		$	97

^(a) Includes approximately $20 million and $32 million, respectively, of additional PTC benefit (grossed-up for tax) as compared to the same periods in 2018, which are flowed back to customers.

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 June 30						Six Months Ended June 30
(Millions of Dollars)	2019			2018			2019			2018
Natural gas revenues	$	308		$	292		$	1,102		$	954
Cost of natural gas sold and transported	(112		)	(104		)	(591		)	(479		)
Natural gas margin	$	196		$	188		$	511		$	475

Changes in natural gas margin:

	Three Months			Six Months
	Ended June 30,			Ended June 30,
(Millions of Dollars)	2019 vs. 2018			2019 vs. 2018
Retail rate increase (Colorado)	$	—		$	12
Estimated impact of weather	1			12
Infrastructure and integrity riders	2			7
Retail sales growth	2			4
Transport sales	1			3
Conservation revenue (offset by expenses)	(1		)	(3		)
Other (net)	3			1
Total increase in natural gas margin	$	8		$	36

O&M Expenses — O&M expenses increased $8 million, or 1.4%, for the second quarter of 2019 and $49 million, or 4.3%, year-to-date. Significant changes are summarized below:

	Three Months			Six Months
	Ended June 30,			Ended June 30,
(Millions of Dollars)	2019 vs. 2018			2019 vs. 2018
Distribution	$	4		$	23
Business systems	7			11
Gas operations	3			4
Plant generation	(4		)	3
Other (net)	(2		)	8
Total increase in O&M expenses	$	8		$	49

• Distribution expenses were higher due to storms, labor and overtime;
• Business systems costs were higher due to increased customer experience transformation program expenses; and
• Natural gas operation expenses increased due to pipeline maintenance.

Depreciation and Amortization — Depreciation and amortization increased $62 million, or 16.4%, for the second quarter of 2019 and $112 million, or 14.7%, year-to-date. Increase was primarily driven by the Rush Creek wind project being placed in-service (recovered in riders), additional amortization of a prepaid pension asset in Colorado related to tax reform settlements (offset in income taxes) and other capital investments.

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $5 million, or 3.6%, for the second quarter of 2019 and $10 million, or 3.5%, 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 $7 million for the second quarter of 2019 and $11 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 $14 million, or 8.0%, for the second quarter of 2019 and $33 million, or 9.5%, 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 $30 million for the second quarter of 2019 compared with 2018. The decrease was primarily driven by lower pretax earnings, an increase in wind PTCs and an increase in plant-related regulatory differences. Wind PTCs flow back to customers and do not have a material impact on net income. The ETR was 9.2% for the second quarter of 2019 compared with 16.9% for the same period in 2018, largely due to the adjustments above.

Income taxes decreased $65 million for the first six months of 2019 compared with 2018. The decrease was primarily driven by an increase in wind PTCs, an increase in plant-related regulatory differences, lower pretax earnings and a reversal of a valuation allowance. Wind PTCs flow back to customers and do not have a material impact on net income. The ETR was 8.1% for the first six months of 2019 compared with 17.0% for the same period in 2018, largely due to the adjustments above. The following table reconciles the difference between the statutory tax rate and the ETR:

	Three Months Ended June 30						Six Months Ended June 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		5.1		(0.1	)	5.0		5.0		—
(Decreases) increases:
Wind PTCs	(11.9	)	(5.4	)	(6.5	)	(10.0	)	(5.8	)	(4.2	)
Plant regulatory differences ^(a)	(5.5	)	(2.4	)	(3.1	)	(5.6	)	(1.8	)	(3.8	)
Other tax credits and allowances (net)	(0.6	)	(1.1	)	0.5		(1.8	)	(1.2	)	(0.6	)
Other (net)	1.2		(0.3	)	1.5		(0.5	)	(0.2	)	(0.3	)
Effective income tax rate	9.2	%	16.9	%	(7.7	)%	8.1	%	17.0	%	(8.9	)%

^(a) Regulatory differences for income tax primarily relate to the flow back of excess deferred taxes to customers through the average rate assumption method and the impact of AFUDC - Equity. Quarterly variations primarily relates to the deferral of the flow back of excess deferred taxes in 2018, as a result of pending regulatory decisions. Treatment of most tax reform items was established prior to the first quarter of 2019, resulting in a reduction in deferred amounts. Income tax benefits associated with the flow back 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)	June 30, 2019		Percentage of Total Capitalization		Dec. 31, 2018		Percentage of Total Capitalization
Current portion of long-term debt	$	553	2	%	$	406	1	%
Short-term debt	1,597		5		1,038		4
Long-term debt	15,996		52		15,803		54
Total debt	18,146		59		17,247		59
Common equity	12,366		41		12,222		41
Total capitalization	$	30,512	100	%	$	29,469	100	%

Credit Facilities — In the second quarter of 2019, Xcel Energy renewed and increased the level of its credit facilities. As of July 29, 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	$	663	$	587	$	1	$	588
PSCo	700		373		327		1		328
NSP-Minnesota	500		203		297		1		298
SPS	500		2		498		242		740
NSP-Wisconsin	150		55		95		1		96
Total	$	3,100	$	1,296	$	1,804	$	246	$	2,050

^(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 June 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 June 30, 2019, NSP-Minnesota’s outstanding letters of credit were as follows:

(Millions of Dollars)	Limit		Amount Outstanding		Available
NSP-Minnesota	$	75	$	23	$	52

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.

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 July 29, 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

2019 Planned Financing Activity — 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 and 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 Bonds	300		Completed	30 Year	3.75
Xcel Energy Inc.	Senior Unsecured Bonds	600		Pending	N/A	N/A
NSP-Minnesota	First Mortgage Bonds	900		Pending	N/A	N/A
PSCo	First Mortgage Bonds	550		Pending	N/A	N/A

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 to purchase the 760 megawatt (MW) natural gas combined cycle (CC) facility for approximately $650 million. NSP-Minnesota currently purchases the energy and capacity of this facility through purchase power agreements (PPAs). The acquisition is projected to provide net customer savings of approximately $50 million to $150 million over the life of the plant.

In May 2019, NSP-Minnesota entered into a partial settlement agreement with several environmental organizations and the Laborers’ International Union of North America. Under the terms of the agreement, the settling parties supported the MEC acquisition and NSP-Minnesota agreed to include (in its preferred plan in the Minnesota resource plan filing) early retirement of the Sherco 3 and King coal plants, as well as 3,000 MW of solar additions before 2030.

In May 2019, the Federal Energy Regulatory Commission (FERC) approved the purchase. In July 2019, the Minnesota Department of Commerce (DOC) and the Minnesota Office of the Attorney General (OAG) recommended the MPUC deny approval of the Mankato acquisition. The DOC and OAG also recommended that if the MPUC were to approve the transaction, that the Commission disallow all or a portion of the acquisitions adjustment as well as require certain other customer protections. The MPUC is expected to hold hearings and make a decision in the third quarter.

NSP-Minnesota — Minnesota Resource Plan — In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The preferred plan would result in an 80% carbon reduction by 2030 and puts NSP on a path to achieving its vision of being 100% carbon-free by 2050. The preferred plan includes the following:

• Extends the life of the Monticello nuclear plant from 2030 to 2040;
• Continues to run the Prairie Island nuclear plant through current end of life (2033 and 2034);
• Includes the MEC acquisition and construction of the Sherco CC natural gas plant;
• Includes the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;
• Adds approximately 1,700 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response, etc.);
• Adds approximately 1,200 MW of wind replacement; and
• Adds approximately 4,000 MW of solar.

Intervening parties will provide recommendations and comments on the resource plan. The MPUC is anticipated to make a final decision on the resource plan in late 2020 or the first half of 2021.

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, pending additional information, including a purchase and sales agreement. NSP-Minnesota subsequently filed additional information, including an executed purchase and sale agreement, to address DOC concerns. Reply comments are due in August, with an MPUC decision expected in the second half of 2019.

NSP-Wisconsin — Rate Case Settlement — In May 2019, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW) seeking approval of a rate case settlement with various intervenors. For NSP-Wisconsin’s electric utility, the settlement agreement results in no change to base 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. A PSCW decision is expected during the third quarter of 2019.

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 historic test year ended Dec. 31, 2018 (adjusted for 2019 capital investment) and incorporates the full impact of tax reform. PSCo has requested rates effective Jan. 1, 2020.

Revenue Request (Millions of Dollars)	2020
Changes since 2014 rate case:
Plant-related growth 2013-2018	$	85
O&M savings, sales growth and other cost reductions	(89		)
Forecasted 2019 capital additions	49
Advanced Grid Intelligence and Security grid modernization	39
Updated cost of capital	32
Previously approved depreciation rates	28
Incremental wildfire mitigation	14
Net increase to revenue	158
Previously authorized costs:
CACJA, TCA and Rush Creek ^(a)	249
Total base revenue request ^(c)	$	408
Expected year-end rate base ^(b)	$	8,221

^(a) Roll-in of Clean Air Clean Jobs Act (CACJA), transmission cost adjustment (TCA) and Rush Creek Wind Project (excluding PTCs) amounts into base rates will not impact total revenue as costs are currently recovered from customers through riders or the fuel clause.
^(b) Base rate request does not include the impact of the proposed Colorado Energy Plan.
^(c) Amounts may not add due to rounding.

The procedural schedule is as follows:

• Answer testimony — Sept. 6, 2019
• Rebuttal testimony — Oct. 8, 2019
• Evidentiary hearing — Nov. 4-13, 2019
• Statement of position — Nov. 22, 2019

PSCo — Colorado 2019 Steam Rate Case — In January 2019, PSCo filed a steam rate case in Colorado seeking a rate increase of $7.3 million, based on a ROE of 10.65%, an equity ratio of 56.29%, a rate base of $63 million and a 2017 historical test year including a capital reach forward for investments in the steam system.

In May 2019, PSCo filed an unopposed settlement agreement with CPUC Staff and the City of Denver. The settlement reflects a rate increase of $6.6 million, a ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. Final rates would be effective in October 2020, with an initial step increase in October 2019. In July 2019, the Administrative Law Judge recommended that the settlement agreement be approved without modification. The settlement is pending a CPUC decision.

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' net revenue increase to New Mexico consumers is expected to be approximately $26 million, or 5.7%, due to fuel cost reductions and PTCs attributable to wind energy provided by the Hale Wind Project. PTCs are being credited to customers through the fuel clause.

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:

• Intervention deadline — Sept. 16, 2019
• 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's 2019 GAAP and ongoing earnings guidance is a range of $2.55 to $2.65 per share.^(a) Key assumptions:

• 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 with 2018 levels.
• Weather-normalized retail firm natural gas sales are projected to be within a range of 2.0% to 3.0% over 2018 levels.
• Capital rider revenue is projected to increase $115 million to $125 million (net of PTCs) over 2018 levels. PTCs are flowed back to customers, through capital riders and reductions to electric margin.
• Purchase capacity costs are expected to decline $25 million to $30 million compared with 2018 levels.
• O&M expenses are projected to decrease approximately 2.0% from 2018 levels.
• Depreciation expense is projected to increase approximately $135 million to $145 million over 2018 levels. 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. A significant portion of the change in depreciation expense reflects an adjustment for the new lease accounting standard, which reclassifies certain expense from electric fuel and purchase power to depreciation and amortization with no impact on earnings.
• Property taxes are projected to increase approximately $15 million to $25 million over 2018 levels.
• Interest expense (net of AFUDC - debt) is projected to increase $80 million to $90 million over 2018 levels.
• AFUDC - equity is projected to decrease approximately $20 million to $30 million from 2018 levels.
• The ETR is projected to be approximately 8% to 10%. The ETR reflects benefits of PTCs which are flowed back 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 2018 base of $2.43 per share, which represents the mid-point of the original 2018 guidance range of $2.37 to $2.47 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 June 30
	2019			2018
Operating revenues:
Electric and natural gas	$	2,557		$	2,640
Other	20			18
Total operating revenues	2,577			2,658
Net income	$	238		$	265
Weighted average diluted common shares outstanding	518			510
Components of EPS — Diluted
Regulated utility	$	0.53		$	0.58
Xcel Energy Inc. and other costs	(0.06		)	(0.06		)
GAAP and ongoing diluted EPS	$	0.46		$	0.52
Cash dividends declared per common share	$	0.41		$	0.38

	Six Months Ended June 30
	2019			2018
Operating revenues:
Electric and natural gas	$	5,676		$	5,571
Other	42			38
Total operating revenues	5,718			5,609
Net income	$	553		$	556
Weighted average diluted common shares outstanding	517			510
Components of EPS — Diluted
Regulated utility	$	1.18		$	1.19
Xcel Energy Inc. and other costs	(0.11		)	(0.10		)
GAAP and ongoing diluted EPS	$	1.07		$	1.09
Book value per share	$	23.92		$	22.90
Cash dividends declared per common share	0.81			0.76