Xcel Energy 2018 Year End Earnings Report

• GAAP 2018 earnings per share were $2.47 compared with $2.25 per share in 2017.
• Ongoing 2018 earnings per share were $2.47 compared with $2.30 per share in 2017.
• Xcel Energy reaffirms 2019 earnings guidance of $2.55 to $2.65 per share.

MINNEAPOLIS--(BUSINESS WIRE)--Xcel Energy Inc. (NASDAQ: XEL) today reported 2018 GAAP and ongoing earnings of $1,261 million, or $2.47 per share, compared with GAAP earnings of $1,148 million or $2.25 per share and ongoing earnings of $1,171 million or $2.30 per share in 2017.

GAAP and ongoing earnings increased as a result of higher electric and natural gas revenues primarily due to favorable weather and sales growth and higher AFUDC. These positive factors were partially offset by increased O&M, depreciation and interest expenses. GAAP earnings for 2017 include the non-recurring negative impact of the TCJA.

“Xcel Energy executed exceptionally well in 2018, achieving our financial targets and delivering outstanding value to customers and stakeholders. For the 14th consecutive year, we have met or exceeded our earnings guidance,” said chairman, president and CEO Ben Fowke. “In addition, throughout our entire company there is great pride that we became the first utility in the nation to announce a vision to deliver 100 percent carbon-free energy to our customers by 2050.”

“Our clean energy leadership is creating economic development opportunities for the communities we serve,” Fowke continued. “This is demonstrated by Google’s recent announcement regarding a new data center in Becker, Minnesota, which would be powered by our renewable energy.”

Earnings Adjusted for Certain Items (Ongoing Earnings)

A reconciliation of ongoing earnings per share (EPS) to generally accepted accounting principles (GAAP) EPS follows. Ongoing earnings is a non-GAAP financial measure. See “Non-GAAP Financial Measures” below for more information.

	Three Months Ended Dec. 31				Twelve Months Ended Dec. 31
Diluted Earnings Per Share	2018		2017		2018		2017
GAAP diluted EPS	$	0.42	$	0.37	$	2.47	$	2.25
Estimated impact of the Tax Cut and Jobs Act (TCJA) ^(a)	—		0.05		—		0.05
Ongoing diluted EPS	$	0.42	$	0.42	$	2.47	$	2.30

^(a)	See Notes 5 and 7.

At 9:00 a.m. CST 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:	5426922

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. CST on Jan. 31 through 12:00 p.m. CST on Feb. 3.

Replay Numbers
US Dial-In:	[phone]
International Dial-In:	[phone]
Access Code:	5426922

Except for the historical statements contained in this release, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including our 2019 EPS guidance, long-term earnings per share 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, 2017 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; unusual weather and climate change, including compliance with any accompanying legislative and regulatory changes; ability of subsidiaries to recover costs from customers; actions of credit rating agencies; 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; 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 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 Dec. 31						Twelve Months Ended Dec. 31
	2018			2017			2018			2017
Operating revenues
Electric	$	2,300		$	2,256		$	9,719		$	9,676
Natural gas	558			520			1,739			1,650
Other	22			20			79			78
Total operating revenues	2,880			2,796			11,537			11,404
Operating expenses
Electric fuel and purchased power	947			906			3,854			3,757
Cost of natural gas sold and transported	305			279			843			823
Cost of sales — other	10			9			35			34
Operating and maintenance expenses	624			582			2,352			2,270
Conservation and demand side management	74			67			290			273
Depreciation and amortization	442			378			1,642			1,479
Taxes (other than income taxes)	139			134			556			545
Total operating expenses	2,541			2,355			9,572			9,181
Operating income	339			441			1,965			2,223
Other expense, net	(7		)	(6		)	(14		)	(10		)
Equity earnings of unconsolidated subsidiaries	10			7			35			30
Allowance for funds used during construction — equity	30			21			108			75
Interest charges and financing costs
Interest charges — includes other financing costs of $7, $6, $25, and $24, respectively	176			165			700			663
Allowance for funds used during construction — debt	(13		)	(9		)	(48		)	(35		)
Total interest charges and financing costs	163			156			652			628
Income before income taxes	209			307			1,442			1,690
Income taxes	(6		)	118			181			542
Net income	$	215		$	189		$	1,261		$	1,148
Weighted average common shares outstanding:
Basic	515			509			511			509
Diluted	515			509			511			509
Earnings per average common share:
Basic	$	0.42		$	0.37		$	2.47		$	2.26
Diluted	0.42			0.37			2.47			2.25

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 the 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, 2017, Xcel Energy recognized an estimated one-time, non-cash, income tax expense of approximately $23 million for net excess deferred tax assets which may not be recovered from customers or not attributable to regulated operations, increased valuation allowances, etc. due to the enactment of the TCJA in December 2017. For the three and twelve months ended Dec. 31, 2018, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings. See Note 7 for further information.

Note 1. Earnings Per Share Summary

The following summarizes diluted EPS for Xcel Energy:

	Three Months Ended Dec. 31
	2018			2017
Diluted Earnings (Loss) Per Share	GAAP and Ongoing Diluted EPS			GAAP Diluted EPS			Impact of TCJA ^(a)			Ongoing Diluted EPS
Public Service Company of Colorado (PSCo)	$	0.17		$	0.19		$	(0.03	)	$	0.16
NSP-Minnesota	0.17			0.15			0.05			0.20
Southwestern Public Service Company (SPS)	0.08			0.06			(0.01		)	0.05
NSP-Wisconsin	0.04			0.04			—			0.04
Equity earnings of unconsolidated subsidiaries ^(a)	0.01			0.05			(0.04		)	0.01
Regulated utility	$	0.47		$	0.49		$	(0.03	)	$	0.46
Xcel Energy Inc. and other	(0.05		)	(0.12		)	0.07			(0.05		)
Total ^(b)	$	0.42		$	0.37		$	0.05		$	0.42

	Twelve Months Ended Dec. 31
	2018			2017
Diluted Earnings (Loss) Per Share	GAAP and Ongoing Diluted EPS			GAAP Diluted EPS			Impact of TCJA ^(a)			Ongoing Diluted EPS
PSCo	$	1.08		$	0.97		$	(0.03	)	$	0.94
NSP-Minnesota	0.96			0.96			0.05			1.01
SPS	0.42			0.31			(0.01		)	0.30
NSP-Wisconsin	0.19			0.16			—			0.16
Equity earnings of unconsolidated subsidiaries ^(a)	0.04			0.07			(0.04		)	0.03
Regulated utility ^(b)	$	2.69		$	2.47		$	(0.03	)	$	2.45
Xcel Energy Inc. and other	(0.22		)	(0.22		)	0.07			(0.15		)
Total ^(b)	$	2.47		$	2.25		$	0.05		$	2.30

^(a)	Includes income taxes.
^(b)	Amounts may not add due to rounding.

Differences between GAAP and ongoing earnings are due to the non-recurring impact of the Tax Cuts and Jobs Act (TCJA) experienced in 2017. See Notes 5 and 7 for additional information. Explanations for operating company results below exclude the offsetting impacts of the TCJA on sales, depreciation and amortization expense and income tax.

PSCo — GAAP and ongoing 2018 earnings increased $0.11 and $0.14 per share, respectively. Increases were driven by higher natural gas margins largely due to a natural gas rate increase, higher electric margins reflecting favorable weather and sales growth, and additional allowance for funds used during construction (AFUDC) associated with the Rush Creek wind project. These items were partially offset by higher operating and maintenance (O&M) expenses, interest charges, depreciation expense and property taxes.

NSP-Minnesota — 2018 GAAP earnings were consistent with 2017, while 2018 ongoing earnings decreased $0.05 per share. The decrease in ongoing earnings reflects higher depreciation expense and O&M expenses. These amounts were partially offset by higher electric and natural gas margins attributable to favorable weather.

SPS — 2018 GAAP and ongoing earnings increased $0.11 and $0.12 per share, respectively. Increases were primarily due to higher electric margins reflecting favorable weather and sales growth and a rate increase in New Mexico, AFUDC related to the Hale County wind project and lower interest charges. Increases were partially offset by higher depreciation expense.

NSP-Wisconsin — 2018 GAAP and ongoing earnings increased $0.03 per share. Increases reflect higher electric and natural gas rates and the impact of favorable weather and sales growth, which were partially offset by higher depreciation.

Xcel Energy Inc. and other — Xcel Energy Inc. and other primarily includes financing costs at the holding company. 2018 GAAP earnings were consistent with 2017, while 2018 ongoing earnings decreased $0.07 per share. Decrease was primarily due to higher interest expense related to additional debt and the change in the federal income tax rate.

Components significantly contributing to the changes in 2018 EPS compared with the same period in 2017 are as follows:

Diluted Earnings (Loss) Per Share	Three Months Ended Dec. 31			Twelve Months Ended Dec. 31
GAAP diluted EPS — 2017	$	0.37		$	2.25
Impact of the TCJA ^(a)	0.05			0.05
Ongoing diluted EPS — 2017	$	0.42		$	2.30
Components of change — 2018 vs. 2017
Higher electric margins (excluding TCJA impacts)^(a)	0.10			0.31
Higher natural gas margins (excluding TCJA impacts)^(a)	0.03			0.13
Higher AFUDC — equity	0.02			0.07
Higher O&M expenses	(0.05		)	(0.10		)
Higher depreciation and amortization (excluding TCJA impacts) ^(a)	(0.04		)	(0.10		)
Higher ETR (excluding TCJA impacts) ^(a)	(0.03		)	(0.07		)
Higher interest charges	(0.02		)	(0.04		)
Higher conservation and demand side management (DSM) program expenses (offset by higher revenues)	(0.01		)	(0.02		)
Higher taxes (other than income taxes)	(0.01		)	(0.01		)
Other, net	0.01			—
GAAP and Ongoing diluted EPS — 2018	$	0.42		$	2.47
^(a)Estimated net impact of the TCJA, including assumptions regarding future regulatory proceedings:
Income tax — rate change and ARAM (net of deferral)	$	0.18		$	0.68
Electric margin reductions (net)	(0.12		)	(0.46		)
Natural gas margin reductions (net)	(0.02		)	(0.06		)
Depreciation and amortization reductions (Colorado prepaid pension)	(0.04		)	(0.11		)
Holding company — interest expense	—			(0.04		)
Total	$	—		$	0.01

The following summarizes the return on equity (ROE) for Xcel Energy and its utility subsidiaries at Dec. 31:

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

ROE — 2017	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Operating Companies		Xcel Energy
GAAP ROE	8.90	%	9.05	%	7.84	%	9.41	%	8.84	%	10.21	%
Impact of the TCJA	(0.24	)	0.45		(0.30	)	0.09		0.03		0.21
Ongoing ROE	8.66	%	9.50	%	7.54	%	9.50	%	8.87	%	10.42	%

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.

The percentage increase (decrease) in normal and actual HDD, CDD and THI is as follows:

	Three Months Ended Dec. 31			Twelve Months Ended Dec. 31
	2018 vs. Normal	2017 vs. Normal	2018 vs. 2017	2018 vs. Normal		2017 vs. Normal		2018 vs. 2017
HDD	6.4%	(4.0)%	9.2%	2.2	%	(10.0	)%	12.2	%
CDD	N/A	N/A	N/A	26.7		6.5		20.5
THI	N/A	N/A	N/A	37.3		(11.3	)	56.9

Weather — The following summarizes the estimated impact of temperature variations on EPS compared with normal weather conditions:

	Three Months Ended Dec. 31									Twelve Months Ended Dec. 31
	2018 vs. Normal			2017 vs. Normal			2018 vs. 2017			2018 vs. Normal			2017 vs. Normal			2018 vs. 2017
Retail electric	$	0.004		$	(0.004	)	$	0.008		$	0.114		$	(0.036	)	$	0.150
Firm natural gas	0.004			(0.003		)	0.007			0.007			(0.023		)	0.030
Total (excluding decoupling)	$	0.008		$	(0.007	)	$	0.015		$	0.121		$	(0.059	)	$	0.180
Decoupling — Minnesota electric	(0.002		)	(0.001		)	(0.001		)	(0.051		)	0.022			(0.073		)
Total (adjusted for recovery from decoupling)	$	0.006		$	(0.008	)	$	0.014		$	0.070		$	(0.037	)	$	0.107

Sales Growth (Decline) — The tables below summarize Xcel Energy and its subsidiaries’ sales growth (decline) for actual and weather-normalized sales in 2018 compared to the same period in 2017:

	Three Months Ended Dec. 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	5.4	%	(0.2	)%	10.1	%	0.6	%	3.3	%
Electric commercial and industrial	2.2		(1.2	)	4.9		0.3		1.4
Total retail electric sales	3.1		(0.9	)	5.5		0.3		1.9
Firm natural gas sales	13.3		9.7		N/A		5.7		11.7

	Three Months Ended Dec. 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential	2.6	%	(0.7	)%	6.0	%	0.9	%	1.6	%
Electric commercial and industrial	1.9		(1.3	)	4.7		0.2		1.3
Total retail electric sales	2.1		(1.1	)	4.7		0.4		1.3
Firm natural gas sales	2.3		6.0		N/A		3.8		3.5

	Twelve Months Ended Dec. 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	3.6	%	5.8	%	8.6	%	5.7	%	5.4	%
Electric commercial and industrial	1.5		1.1		5.4		3.2		2.4
Total retail electric sales	2.2		2.5		5.9		3.9		3.2
Firm natural gas sales	9.3		14.6		N/A		13.1		11.3

	Twelve Months Ended Dec. 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential	1.8	%	(0.5	)%	2.0	%	0.2	%	0.8	%
Electric commercial and industrial	1.2		(0.4	)	4.6		2.3		1.5
Total retail electric sales	1.3		(0.4	)	4.1		1.7		1.3
Firm natural gas sales	2.2		2.7		N/A		3.1		2.4

Weather-normalized Electric Sales Growth (Decline) — Year-To-Date

• PSCo — Higher residential sales growth reflects customer additions and slightly higher 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, food products, metal mining and oil and gas extraction industries.
• NSP-Minnesota — Residential sales decrease was a result of lower use per customer, partially offset by customer growth. The decline in C&I sales was due to an increase in customers offset by lower use per customer. Increased sales to large customers in manufacturing and energy were offset by declines in services.
• SPS — Residential sales grew largely due to higher use per customer and customer additions. The increase in C&I sales was driven by the oil and natural gas industry in the Permian Basin.
• NSP-Wisconsin — Sales growth was primarily attributable to customer additions, partially offset by lower use per customer. C&I growth was largely due to higher use per large customer, customer additions and increased sales to sand mining and energy industries.

Weather-normalized Natural Gas Sales Growth — Year-To-Date

• Higher natural gas sales reflect an increase in the number of customers combined with increasing 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. Electric margin was reduced by approximately $105 million in 2018 and $130 million in 2017 for PTCs (grossed up for federal income tax) which were returned to customers. Margin reductions for PTCs are largely offset by income tax benefits.

The following details the electric revenues and margin before and after the impact of the TCJA:

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
(Millions of Dollars)	2018			2017			2018			2017
Electric revenues before TCJA impact	$	2,382		$	2,256		$	10,046		$	9,676
Electric fuel and purchased power before TCJA impact	(951		)	(906		)	(3,867		)	(3,757		)
Electric margin before TCJA impact	$	1,431		$	1,350		$	6,179		$	5,919
TCJA impact (offset as a reduction in income tax)	(78		)	—			(314		)	—
Electric margin	$	1,353		$	1,350		$	5,865		$	5,919

Components of the changes in electric margin are as follows:

(Millions of Dollars)	Three Months Ended Dec. 31 2018 vs. 2017			Twelve Months Ended Dec. 31 2018 vs. 2017
Estimated impact of weather (net of Minnesota decoupling)	$	6		$	63
Retail sales growth (net of Minnesota decoupling and sales true-up)	17			52
Non-fuel riders	27			45
Purchased capacity costs	4			38
Wholesale transmission revenue (net)	12			31
Retail rate increase (Wisconsin, New Mexico and Michigan)	7			20
Other (net)	8			11
Total increase in electric margin before TCJA impact	$	81		$	260
TCJA impact (offset as a reduction in income tax)	(78		)	(314		)
Total increase (decrease) in electric margin	$	3		$	(54	)

Natural Gas Margin — Total natural gas expense varies with changing sales requirements and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin before and after the impact of the TCJA:

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
(Millions of Dollars)	2018			2017			2018			2017
Natural gas revenues before TCJA impact	$	571		$	520		$	1,778		$	1,650
Cost of natural gas sold and transported	(305		)	(279		)	(843		)	(823		)
Natural gas margin before TCJA impact	$	266		$	241		$	935		$	827
TCJA impact (offset as a reduction in income tax)	(13		)	—			(39		)	—
Natural gas margin	$	253		$	241		$	896		$	827

The components of the changes in natural gas margin are as follows:

(Millions of Dollars)	Three Months Ended Dec. 31 2018 vs. 2017			Twelve Months Ended Dec. 31 2018 vs. 2017
Retail rate increase (Colorado, Wisconsin and Michigan)	$	17		$	58
Estimated impact of weather	6			24
Infrastructure and integrity riders	(1		)	13
Sales growth	4			6
Conservation revenue (offset by expenses)	—			3
Other (net)	(1		)	4
Total increase in natural gas margin before TCJA impact	$	25		$	108
TCJA impact (offset as a reduction in income tax)	(13		)	(39		)
Total increase in natural gas margin	$	12		$	69

O&M Expenses — O&M expenses increased $42 million, or 7.2 percent, for the fourth quarter of 2018 and increased $82 million, or 3.6 percent, for 2018. Significant changes are summarized below:

(Millions of Dollars)	Three Months Ended Dec. 31 2018 vs. 2017		Twelve Months Ended Dec. 31 2018 vs. 2017
Business systems and contract labor	$	10	$	39
Distribution costs	6		19
Natural gas systems damage prevention and other remediation	6		12
Generation plant costs (including increased wind O&M)	9		11
Nuclear plant operations and amortization	7		(9		)
Other (net)	4		10
Total increase in O&M expenses	$	42	$	82

• Business systems and contract labor costs increased due to growing network and storage needs, cybersecurity, initiatives to support our customer strategy, and initiatives to improve business processes;
• Distribution costs reflect higher maintenance expenses, including vegetation management; and
• Nuclear plant operations and amortization are lower largely reflecting savings initiatives and reduced refueling outage costs.

Conservation and DSM Program Expenses — Conservation and DSM program expenses increased $7 million, or 10.4 percent, for the fourth quarter of 2018 and increased $17 million, or 6.2 percent, for 2018. The increase was primarily due to recovery for conservation programs to assist customers in reducing energy use. Conservation and DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may vary from when costs are incurred.

Depreciation and Amortization — Depreciation and amortization increased $64 million, or 16.9 percent for the fourth quarter of 2018 and increased $163 million, or 11.0 percent, for 2018. The increase was primarily driven by capital investments and additional amortization of a prepaid pension asset in Colorado (approximately $75 million) related to TCJA settlements, which were offset by lower income taxes.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $5 million, or 3.7 percent, for the fourth quarter of 2018 and increased $11 million, or 2.0 percent, for 2018. The increase was primarily due to higher property taxes.

AFUDC, Equity and Debt — AFUDC increased $13 million for the fourth quarter of 2018 and increased $46 million for 2018. The increase was primarily due to the Rush Creek and Hale wind projects and other capital investments.

Interest Charges — Interest expense increased $11 million, or 6.7 percent, for the fourth quarter of 2018 and increased $37 million, or 5.6 percent, for 2018. The increase was related to higher debt levels to fund capital investments, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense decreased $124 million for the fourth quarter of 2018. The decrease was primarily driven by a lower federal tax rate due to the TCJA, lower pretax earnings, a one time, non-cash, income tax expense related to TCJA in 2017, an increase in plant-related regulatory differences related to ARAM^(b) (net of deferrals), 2018 non-plant excess accumulated deferred income tax amortization, and an increase in wind PTCs. The ETR was (2.9) percent for the fourth quarter of 2018 compared with 38.4 percent for the same period in 2017. The lower ETR in 2018 was largely due to the adjustments above.

Income tax expense decreased $361 million for 2018. The decrease was primarily driven by a lower federal tax rate due to the TCJA, lower pretax earnings, a one time, non-cash, income tax expense related to TCJA in 2017, an increase in plant-related regulatory differences related to ARAM^(b) (net of deferrals), 2018 non-plant excess accumulated deferred income tax amortization, and the impact of 2018 investment tax credits. These were partially offset by a higher tax benefit for the resolution of past appeals/audits in 2017 and a higher tax benefit for adjustments in 2017. The ETR was 12.6 percent for 2018 compared with 32.1 percent for 2017. The lower ETR in 2018 was largely due to the adjustments above.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
	2018		2017		2018 vs 2017		2018		2017		2018 vs 2017
Federal statutory rate	21.0	%	35.0	%	(14.0	)%	21.0	%	35.0	%	(14.0	)%
State tax (net of federal tax effect)	5.0		3.9		1.1		5.0		4.1		0.9
Increase (decreases) in tax from:
Wind production tax credits (PTCs)^(a)	(10.5	)	(5.2	)	(5.3	)	(5.2	)	(4.7	)	(0.5	)
Regulatory differences - ARAM ^(b)	(6.8	)	(0.1	)	(6.7	)	(5.8	)	(0.1	)	(5.7	)
Regulatory differences - ARAM deferral ^(c)	0.8		—		0.8		3.9		—		3.9
Regulatory differences - reversal of prior quarters' ARAM deferral ^(c)	(3.6	)	—		(3.6	)	(3.3	)	—		(3.3	)
Regulatory differences - other utility plant items	(1.9	)	(0.7	)	(1.2	)	(1.0	)	(0.7	)	(0.3	)
Tax reform	—		7.5		(7.5	)	—		1.4		(1.4	)
Amortization of excess utility nonplant deferred taxes	(5.5	)	—		(5.5	)	(0.7	)	—		(0.7	)
Other (net)	(1.4	)	(2.0	)	0.6		(1.3	)	(2.9	)	1.6
Effective income tax rate	(2.9	)%	38.4	%	(41.3	)%	12.6	%	32.1	%	(19.5	)%

^(a)	PTCs of $75 million and $78 million were recorded in 2018 and 2017, respectively. Impact is largely offset by electric margin reductions for customer refunds.
^(b)	The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.
^(c)	ARAM has been deferred when regulatory treatment has not been established. As Xcel Energy received direction from its regulatory commissions regarding the return of excess deferred taxes to customers, the ARAM deferral was reversed. This resulted in a reduction to tax expense with a corresponding reduction to revenue	.

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

The capital structure of Xcel Energy is as follows:

	As of Dec. 31, 2018				As of Dec. 31, 2017
(Millions of Dollars)	Capital Structure		Percentage of Total Capitalization		Capital Structure		Percentage of Total Capitalization
Current portion of long-term debt	$	406	1	%	$	457	2	%
Short-term debt	1,038		4		814		3
Long-term debt	15,803		54		14,520		53
Total debt	17,247		59		15,791		58
Common equity	12,222		41		11,455		42
Total capitalization	$	29,469	100	%	$	27,246	100	%

Credit Facilities — As of Jan. 28, 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.	$	1,500	$	505	$	995	$	1	$	996
PSCo	700		413		287		—		287
SPS	400		64		336		1		337
NSP-Minnesota	500		368		132		2		134
NSP-Wisconsin	150		55		95		—		95
Total	$	3,250	$	1,405	$	1,845	$	4	$	1,849

^(a)	Credit facilities expire in June 2021, with the exception of Xcel Energy Inc.’s $500 million 364-day term loan agreement, which expires in December 2019.
^(b)	Includes outstanding commercial paper and letters of credit.

Credit Ratings — Access to the capital market at reasonable terms is dependent in part on credit ratings. The following ratings reflect the views of Moody’s Investors Service (Moody’s), Standard & Poor’s Rating Services (Standard & Poor’s), and Fitch Ratings (Fitch).

The highest credit rating for debt is Aaa/AAA and the lowest investment grade rating is Baa3/BBB-. The highest rating for commercial paper is P-1/A-1/F-1 and the lowest rating is P-3/A-3/F-3. A security rating is not a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

As of Jan 28, 2019, the following represents the credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries:

Credit Type	Company	Moody’s	Standard & Poor’s	Fitch
Senior Unsecured Debt	Xcel Energy Inc.	A3	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

In October 2018, Moody’s changed the ratings outlook for Xcel Energy Inc., from stable to negative due to the adverse impact of the TCJA on credit metrics and liquidity. All other subsidiary outlooks are stable.

Planned Financing Activity — Xcel Energy Inc. and its utility subsidiaries’ 2019 financing plans reflect the following:

• Xcel Energy Inc. — approximately $700 million of senior notes and approximately $75 to $80 million of equity through the dividend reinvestment and benefit programs;
• NSP-Minnesota — approximately $900 million of first mortgage bonds;
• PSCo — approximately $800 million of first mortgage bonds; and
• SPS — approximately $250 million of first mortgage bonds

Term Loan Agreement — Xcel Energy renewed and amended its $500 million 364-Day Term Loan Agreement in December 2018. As of Dec. 31, 2018, Xcel had $250 million outstanding and is entitled to an additional $250 million until March 4, 2019.

Equity Offering — In November 2018, Xcel Energy Inc. entered into a forward sale agreement for up to 9.4 million shares of Xcel Energy common stock. The cash proceeds at settlement are expected to be approximately $450 million to $460 million. Earlier in 2018, Xcel Energy had issued 4.7 million shares of common stock with net proceeds of $224.7 million through an at-the market program.

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 Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company to purchase the 760 megawatt (MW) natural gas combined cycle Mankato Energy Center for approximately $650 million. NSP-Minnesota previously contracted to purchase the energy and capacity of this facility through a power purchase agreement. The asset acquisition is anticipated to close in mid-2019, subject to regulatory approvals. The acquisition is projected to provide net customer savings of approximately $50 to $150 million over the life of the plant.

NSP-Minnesota — Wind Repowering Acquisition — In December 2018, NSP-Minnesota filed with the Minnesota Public Utilities Commission (MPUC) to acquire the Jeffers and Community Wind North wind farms 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 to qualify for the 100 percent PTC benefit. The acquisition is projected to provide customer savings of approximately $7 million over the life of the wind farms. The cost of the acquisition is $135 million and is pending MPUC approval.

PSCo — Pipeline System Integrity Adjustment (PSIA) Rider — In October 2018, the Colorado Public Utilities Commission (CPUC) approved a settlement agreement to extend the PSIA rider through 2021.

PSCo – Colorado Energy Plan (CEP) — In September 2018, the CPUC issued a written order approving PSCo’s preferred CEP portfolio, which included the retirement of the two coal-fired generation units, Comanche Unit 1 (in 2022) and Comanche Unit 2 (in 2025), and the following additions:

	Total Capacity	PSCo's Ownership
Wind generation	1,100 MW	500 MW
Solar generation	700 MW	—
Battery storage	275 MW	—
Natural gas generation	380 MW	380 MW

PSCo’s investment is expected to be approximately $1 billion, including transmission to support the significant increase in renewable generation. PSCo’s investment includes the 500 MW Cheyenne Ridge wind farm and the 345 kilovolt generation tie line, as well as the Shortgrass Substation for which certificates of public convenience and necessity (CPCNs) were filed in December 2018. A CPUC decision is anticipated by May 2019. A CPCN for the natural gas generation facility is anticipated to be filed by mid-2019.

Note 5. TCJA Regulatory Proceedings

The following details the status of regulatory decisions in each state where Xcel Energy operates.

NSP-Minnesota — Minnesota — In 2018, the MPUC ordered NSP-Minnesota to refund the 2018 impacts of TCJA, including $135 million to electric customers, $6 million to natural gas customers and low income program funding of $2 million.

NSP-Minnesota — South Dakota — In July 2018, the South Dakota Public Utilities Commission approved a settlement providing a one-time customer refund of $11 million for the 2018 impact of the TCJA, while NSP-Minnesota would retain the TCJA benefits in 2019 and 2020 in exchange for a two-year rate case moratorium.

NSP-Minnesota — North Dakota — Natural Gas — In November 2018, the North Dakota Public Service Commission (NDPSC) approved a TCJA settlement in which NSP-Minnesota will amortize $1 million annually of the regulatory asset for the remediation of the manufactured gas plant (MGP) site in Fargo, N.D. and retain the TCJA savings to offset the MGP amortization expense.

NSP-Minnesota — North Dakota — Electric — In October 2018, NSP-Minnesota and the NDPSC Staff reached a settlement which included a one-time customer refund of $10 million for 2018, while NSP-Minnesota would retain the TCJA benefits in 2019 and 2020 in exchange for a two-year rate case moratorium. In December 2018, the NDPSC ordered NSP-Minnesota to refund its customers the $10 million. A decision on the settlement is anticipated later in 2019.

NSP-Wisconsin — Wisconsin — In May 2018, the Public Service Commission of Wisconsin issued an order which requires customer refunds of $27 million and defers approximately $5 million until NSP-Wisconsin’s next rate case proceeding.

NSP-Wisconsin — Michigan — In May 2018, the Michigan Public Service Commission approved electric and natural gas TCJA settlement agreements. Most of the electric TCJA benefits were reflected in NSP-Wisconsin’s approved Michigan 2018 electric base rate case. The return of natural gas TCJA benefits is expected to be completed in 2019.

PSCo — Colorado Natural Gas — In February 2018, the Administrative Law Judge recommended approval of a TCJA settlement agreement, which included a $20 million reduction to PSCo’s provisional rates effective March 1, 2018. In September 2018, PSCo revised its 2018 TCJA benefit estimate to $24 million and requested an equity ratio of 56 percent to offset the negative impact of the TCJA on credit metrics. In December 2018, the CPUC approved an equity ratio of 54.6 percent and utilized the remainder of the TCJA benefit to reduce an existing prepaid pension asset. In addition, the CPUC ordered the 2018 excess non-plant ADIT benefits of $11.1 million be utilized to accelerate amortization of the prepaid pension asset.

PSCo — Colorado Electric — In 2018, the CPUC approved a TCJA settlement that included a customer refund of $42 million in 2018, with the remainder of the $59 million of TCJA benefits to be used to accelerate the amortization of an existing prepaid pension asset. For 2019, the expected customer refund is estimated to be $67 million, and amortization of the prepaid pension asset is estimated to be $34 million. Impacts of the TCJA for 2020 and future years are expected to be addressed in a future electric rate case.

SPS — Texas — In December 2018, the Public Utility Commission of Texas approved a rate settlement which fully reflects the TCJA cost impacts and results in no change in customer rates or refunds and SPS’ actual capital structure, which SPS has informed the parties it intends to be up to a 57 percent equity ratio to offset the negative impacts on its credit metrics and potentially its credit ratings.

SPS — New Mexico — In September 2018, the New Mexico Public Regulation Commission issued an order in SPS’ 2017 electric rate case, which included a refund of the 2018 impact of the TCJA. In September 2018, SPS filed an appeal with the New Mexico Supreme Court (NMSC) of the rate case order, including the order to refund retroactive TCJA savings to customers. In September 2018, the NMSC granted a temporary stay to delay the implementation of the retroactive TCJA refund until the NMSC issues its decision on SPS’ appeal of the rate case order. The NMSC is not expected to issue its decision until late 2019.

Note 6. 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 year.
• Weather-normalized retail electric sales are projected to be relatively consistent with 2018 levels.
• Weather-normalized retail natural gas sales are projected to be within a range of 0.0 percent to 1.0 percent 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, primarily through capital riders as 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 be consistent with 2017 levels.
• Depreciation expense is projected to increase approximately $120 million to $130 million over 2018 levels. Depreciation expense includes $34 million for the amortization of a prepaid pension asset at PSCo, which is TCJA related and will not impact 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 $90 million to $100 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 6 percent to 8 percent. The ETR reflects benefits of PTCs which are flowed back to customers through electric margin.
• Assumptions do not include the impact for the upcoming adoption of the new lease accounting standard, effective 2019. Xcel Energy does not expect changes in the accounting for leases to impact earnings, but it may result in variations in certain line items within the income statement.

^(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 percent 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 percent;
• Target a dividend payout ratio of 60 to 70 percent; and
• Maintain senior secured debt credit ratings in the A range.

Note 7. Non-GAAP Reconciliation

Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating the company and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and communicating its earnings outlook to analysts and investors.

A reconciliation of GAAP earnings (net income) to ongoing earnings is as follows:

	Three Months Ended Dec. 31				Twelve Months Ended Dec. 31
(Millions of Dollars)	2018		2017		2018		2017
GAAP earnings	$	215	$	189	$	1,261	$	1,148
Estimated impact of TCJA	—		23		—		23
Ongoing earnings	$	215	$	212	$	1,261	$	1,171

Impact of the TCJA — Due to the enactment of the TCJA in December 2017, Xcel Energy recognized an estimated one-time, non-cash, income tax expense of approximately $23 million in the fourth quarter of 2017 for net excess deferred tax assets which may not be recovered from customers or not attributable to regulated operations, increased valuation allowances, etc. Given the non-recurring nature of the TCJA’s broad and sweeping reform of the IRC, the income tax expense associated with the TCJA enactment has been excluded from Xcel Energy’s 2017 ongoing earnings.

XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (Unaudited)
(amounts in millions, except per share data)
	Three Months Ended Dec. 31
	2018			2017
Operating revenues:
Electric and natural gas	$	2,858		$	2,776
Other	22			20
Total operating revenues	2,880			2,796
Net income	$	215		$	189
Weighted average diluted common shares outstanding	515			509
Components of EPS — Diluted
Regulated utility	$	0.47		$	0.49
Xcel Energy Inc. and other	(0.05		)	(0.12		)
GAAPdiluted EPS	0.42			0.37
Impact of the TCJA ^(a)	—			0.05
Ongoing diluted EPS	$	0.42		$	0.42
Cash dividends declared per common share	$	0.38		$	0.36

	Twelve Months Ended Dec. 31
	2018			2017
Operating revenues:
Electric and natural gas	$	11,458		$	11,326
Other	79			78
Total operating revenues	11,537			11,404
Net income	$	1,261		$	1,148
Weighted average diluted common shares outstanding	511			509
Components of EPS — Diluted
Regulated utility	$	2.69		$	2.47
Xcel Energy Inc. and other	(0.22		)	(0.22		)
GAAP diluted EPS	2.47			2.25
Impact of the TCJA ^(a)	—			0.05
Ongoing diluted EPS	$	2.47		$	2.30
Cash dividends declared per common share	$	1.52		$	1.44
Book value per share	$	23.77		$	22.56

^(a)	See Notes 5 and 7.