Xcel Energy 2016 Year End Earnings Report

• GAAP 2016 earnings per share were $2.21 compared with $1.94 per share in 2015.
• Ongoing 2016 earnings per share were $2.21 compared with $2.09 per share in 2015.
• Xcel Energy reaffirms 2017 earnings guidance of $2.25 to $2.35 per share.

MINNEAPOLIS--(BUSINESS WIRE)--Xcel Energy Inc. (NYSE: XEL) today reported 2016 GAAP and ongoing earnings of $1,123 million, or $2.21 per share, compared with GAAP earnings of $984 million, or $1.94 per share, and ongoing earnings of $1,064 million, or $2.09 per share, in 2015.

Increases in electric and natural gas margins were primarily driven by higher rates and riders across various jurisdictions to recover our capital investments and the favorable impact of weather as compared with the previous year. These positive factors and a lower effective tax rate were partially offset by higher depreciation, interest charges and property taxes.

“We had an excellent year,” said Chairman, President and CEO Ben Fowke. “We achieved our financial targets and maintained a disciplined approach to managing costs. Our achievements in 2016 were the result of dedicated cost management, a continued focus on operational and commercial excellence, commitment to stakeholder collaboration and an engaged workforce. These fundamentals are the hallmark of Xcel Energy, and why I am so proud of our long track record of success.”

“We also made significant advancements in our steel-for-fuel growth strategy. We completed the Courtenay Wind Farm, gained approval for the Rush Creek project in Colorado, proposed ownership of 750 megawatts of wind projects in the Upper Midwest, entered into a turbine agreement that secures the full production tax credit for the benefit of our customers and are pursuing investments of 500 to 1,000 megawatts of wind ownership at SPS. These investments will deliver significant value to our customers and shareholders,” concluded Fowke.

Xcel Energy reaffirms its 2017 earnings guidance of $2.25 to $2.35 per share, which is dependent on the key assumptions listed in Note 5.

Earnings Adjusted for Certain Items (Ongoing Earnings)

The following table provides a reconciliation of ongoing earnings per share (EPS) to generally accepted accounting principles (GAAP) EPS:

	Three Months Ended Dec. 31				Twelve Months Ended Dec. 31
Diluted Earnings (Loss) Per Share	2016		2015		2016		2015
Ongoing diluted EPS	$	0.45	$	0.41	$	2.21	$	2.09
Loss on Monticello life cycle management/extended power uprate project ^(a)	—		—		—		(0.16		)
GAAP diluted EPS ^(b)	$	0.45	$	0.41	$	2.21	$	1.94
^(a) See Note 6.
^(b) Amounts may not add due to rounding.

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:	3999244

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 Feb. 2 through 10:59 p.m. CST on Feb. 6.

Replay Numbers
US Dial-In:	[phone]
International Dial-In:	[phone]
Access Code:	3999244

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 2017 earnings per share guidance and assumptions, are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” 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, 2015, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016, June 30, 2016 and Sept. 30, 2016, and subsequent securities filings, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by Xcel Energy; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; 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 thousands, except per share data)
	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
	2016			2015			2016			2015
Operating revenues
Electric	$	2,290,556		$	2,170,183		$	9,499,781		$	9,275,986
Natural gas	484,868			455,935			1,531,412			1,672,081
Other	19,227			19,703			75,727			76,419
Total operating revenues	2,794,651			2,645,821			11,106,920			11,024,486
Operating expenses
Electric fuel and purchased power	962,602			893,390			3,717,685			3,762,953
Cost of natural gas sold and transported	262,935			239,685			732,689			904,794
Cost of sales — other	10,850			9,800			36,075			36,216
Operating and maintenance expenses	562,161			583,577			2,326,558			2,329,670
Conservation and demand side management program expenses	67,518			59,419			244,784			224,679
Depreciation and amortization	332,146			296,703			1,303,203			1,124,524
Taxes (other than income taxes)	131,089			122,237			532,071			511,675
Loss on Monticello life cycle management/extended power uprate project	—			—			—			129,463
Total operating expenses	2,329,301			2,204,811			8,893,065			9,023,974
Operating income	465,350			441,010			2,213,855			2,000,512
Other income (expense), net	1,562			(348		)	7,950			5,400
Equity earnings of unconsolidated subsidiaries	9,623			10,030			42,123			34,390
Allowance for funds used during construction — equity	15,505			15,208			60,547			55,936
Interest charges and financing costs
Interest charges — includes other financing costs of $6,144, $6,357, $25,170, and $24,175, respectively	161,627			153,554			646,907			595,282
Allowance for funds used during construction — debt	(6,822		)	(6,908		)	(27,028		)	(26,248		)
Total interest charges and financing costs	154,805			146,646			619,879			569,034
Income before income taxes	337,235			319,254			1,704,596			1,527,204
Income taxes	109,758			110,229			581,217			542,719
Net income	$	227,477		$	209,025		$	1,123,379		$	984,485
Weighted average common shares outstanding:
Basic	508,656			508,312			508,794			507,768
Diluted	509,421			508,738			509,465			508,168
Earnings per average common share:
Basic	$	0.45		$	0.41		$	2.21		$	1.94
Diluted	0.45			0.41			2.21			1.94
Cash dividends declared per common share	$	0.34		$	0.32		$	1.36		$	1.28

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.

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The diluted earnings and EPS of each subsidiary as well as the return on equity (ROE) of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. Ongoing diluted EPS and ongoing ROE for Xcel Energy and by subsidiary are financial measures not recognized under GAAP. Ongoing diluted EPS is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary, adjusted for certain nonrecurring items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing ROE is calculated by dividing the net income or loss attributable to the controlling interest of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average common stockholders’ or stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as alternatives to measures calculated and reported in accordance with GAAP.

Note 1. Earnings Per Share Summary

The following table summarizes the diluted EPS for Xcel Energy:

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
Diluted Earnings (Loss) Per Share	2016			2015			2016			2015
NSP-Minnesota	$	0.21		$	0.20		$	0.96		$	0.85
Public Service Company of Colorado (PSCo)	0.17			0.16			0.91			0.92
Southwestern Public Service Company (SPS)	0.06			0.04			0.30			0.25
NSP-Wisconsin	0.03			0.03			0.14			0.15
Equity earnings of unconsolidated subsidiaries	0.01			0.01			0.05			0.04
Regulated utility ^(a)	0.48			0.44			2.35			2.21
Xcel Energy Inc. and other	(0.04		)	(0.03		)	(0.15		)	(0.11		)
Ongoing diluted EPS ^(a)	0.45			0.41			2.21			2.09
Loss on Monticello life cycle management (LCM)/ extended power uprate (EPU) project ^(b)	—			—			—			(0.16		)
GAAP diluted EPS ^(a)	$	0.45		$	0.41		$	2.21		$	1.94
^(a) Amounts may not add due to rounding.
^(b) See Note 6.

NSP-Minnesota — 2016 GAAP earnings increased due to the 2015 loss on Monticello LCM/EPU project, see Note 6 for further information. In addition, GAAP and ongoing earnings increased $0.11 per share due to the following: higher electric margins primarily driven by an interim electric rate increase in Minnesota (net of estimated provision for refund); non-fuel riders; the favorable impact of weather; and a lower effective tax rate (ETR). These positive factors were partially offset by higher depreciation, operating and maintenance (O&M) expenses, interest charges and property taxes.

PSCo — Earnings decreased $0.01 per share for 2016. The positive impact of higher natural gas margins (primarily due to a rate increase), sales growth and a lower estimated electric earnings test refund, were more than offset by increased depreciation and interest charges.

SPS — Earnings increased $0.05 per share for 2016. Higher electric margins and lower O&M expenses were partially offset by an increase in depreciation and interest charges.

NSP-Wisconsin — Earnings decreased $0.01 per share for 2016. The positive impact of higher electric margins (primarily driven by an electric rate increase) was more than offset by higher O&M expenses and depreciation.

Equity earnings of unconsolidated subsidiaries — Earnings of unconsolidated subsidiaries increased $0.01 per share in 2016 due to facility expansion and increased sales at WYCO Development, LLC, a joint venture which develops and leases natural gas pipelines, storage and compression facilities.

Xcel Energy Inc. and other — Xcel Energy Inc. and other includes financing costs at the holding company and other items.

The decrease in earnings was primarily related to higher long-term debt levels.

The following table summarizes significant components contributing to the changes in 2016 EPS compared with the same period in 2015:

	Three Months			Twelve Months
Diluted Earnings (Loss) Per Share	Ended Dec. 31			Ended Dec. 31
2015 GAAP diluted EPS	$	0.41		$	1.94
Loss on Monticello LCM/EPU project ^(a)	—			0.16
2015 ongoing diluted EPS ^(b)	$	0.41		$	2.09
Components of change — 2016 vs. 2015
Higher electric margins	0.06			0.32
Lower ETR	0.01			0.06
Higher natural gas margins	0.01			0.04
Higher depreciation and amortization	(0.04		)	(0.21		)
Higher interest charges	(0.01		)	(0.06		)
Higher taxes (other than income taxes)	(0.01		)	(0.02		)
Lower O&M expenses	0.03			—
Other, net	(0.01		)	(0.01		)
2016 GAAP and ongoing diluted EPS	$	0.45		$	2.21

									Operating
ROE — 2016	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Companies		Xcel Energy
2016 GAAP and ongoing ROE	9.29	%	8.92	%	8.14	%	8.63	%	8.94	%	10.39	%
									Operating
ROE — 2015	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Companies		Xcel Energy
2015 ongoing ROE	8.72	%	9.33	%	7.56	%	10.45	%	8.91	%	10.22	%
Loss on Monticello LCM/ EPU project ^(a)	(1.49	)	—		—		(0.42	)	(0.62	)	(0.76	)
2015 GAAP ROE	7.23	%	9.33	%	7.56	%	10.03	%	8.29	%	9.46	%
^(a) See Note 6.
^(b) Amounts may not add due to rounding.

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 the average customer historically uses per degree of temperature. Accordingly, deviations in weather 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 as defined above to derive the amount of demand associated with the weather impact.

The percentage increase (decrease) in normal and actual HDD, CDD and THI are provided in the following table:

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
	2016 vs.		2015 vs.		2016 vs.		2016 vs.		2015 vs.		2016 vs.
	Normal		Normal		2015		Normal		Normal		2015
HDD	(14.5	)%	(14.1	)%	(0.2	)%	(13.4	)%	(7.9	)%	(5.5	)%
CDD ^(a)	N/A		N/A		N/A		11.1		6.2		5.1
THI ^(a)	N/A		N/A		N/A		7.7		(2.3	)	10.9
^(a) CDD and THI have no meaningful impact on fourth quarter sales.

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

	Three Months Ended Dec. 31								Twelve Months Ended Dec. 31
	2016 vs.			2015 vs.			2016 vs.		2016 vs.			2015 vs.			2016 vs.
	Normal			Normal			2015		Normal			Normal			2015
Retail electric	$	(0.009	)	$	(0.016	)	$	0.007	$	0.002		$	(0.020	)	$	0.022
Firm natural gas	(0.011		)	(0.011		)	—		(0.025		)	(0.018		)	(0.007		)
Total	$	(0.020	)	$	(0.027	)	$	0.007	$	(0.023	)	$	(0.038	)	$	0.015

Sales Growth (Decline) — The following tables summarize Xcel Energy and its utility subsidiaries’ sales growth (decline) for actual and weather-normalized sales in 2016 compared to the same period in 2015:

	Three Months Ended Dec. 31
	NSP-Minnesota		PSCo			SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential ^(a)	(0.4	)%	(5.4	)%		(1.4	)%	2.9	%	(2.2	)%
Electric commercial and industrial	(1.0	)	0.4			(0.4	)	0.7		(0.3	)
Total retail electric sales	(0.8	)	(1.4	)		(0.4	)	1.1		(0.8	)
Firm natural gas sales	7.9		(8.9	)		N/A		6.6		(3.6	)
	Three Months Ended Dec. 31
	NSP-Minnesota		PSCo			SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential ^(a)	(1.3	)%	(2.5	)%		(1.4	)%	(0.1	)%	(1.7	)%
Electric commercial and industrial	(1.0	)	0.5			(0.4	)	0.4		(0.3	)
Total retail electric sales	(1.1	)	(0.4	)		(0.4	)	0.1		(0.6	)
Firm natural gas sales	0.4		(2.2	)		N/A		(3.4	)	(1.5	)
	Twelve Months Ended Dec. 31
	NSP-Minnesota		PSCo			SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential ^(a)	1.2	%	1.8		%	(1.6	)%	0.3	%	0.9		%
Electric commercial and industrial	(0.5	)	(0.4		)	1.1		(0.1	)	—
Total retail electric sales	—		0.4			0.7		(0.1	)	0.3
Firm natural gas sales	(4.1	)	(1.1		)	N/A		(7.4	)	(2.4		)
	Twelve Months Ended Dec. 31
	NSP-Minnesota		PSCo			SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential ^(a)	0.1	%	1.9		%	(1.3	)%	(0.2	)%	0.5		%
Electric commercial and industrial	(0.8	)	(0.4		)	0.8		(0.2	)	(0.3		)
Total retail electric sales	(0.5	)	0.4			0.5		(0.3	)	—
Firm natural gas sales	(0.3	)	(0.2		)	N/A		(4.3	)	(0.5		)
	Twelve Months Ended Dec. 31 (Excluding Leap Day) ^(b)
	NSP-Minnesota		PSCo			SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized - adjusted for leap day
Electric residential ^(a)	(0.2	)%	1.6		%	(1.6	)%	(0.6	)%	0.3		%
Electric commercial and industrial	(1.0	)	(0.7		)	0.5		(0.5	)	(0.5		)
Total retail electric sales	(0.8	)	0.1			0.2		(0.6	)	(0.3		)
Firm natural gas sales	(0.8	)	(0.7		)	N/A		(4.8	)	(1.0		)

^(a)	Extreme weather variations and additional factors such as windchill and cloud cover may not be reflected in weather-normalized and actual growth estimates.
^(b)	The estimated impact of the 2016 leap day is excluded to present a more comparable year-over-year presentation. The estimated impact of the additional day of sales in 2016 was approximately 20-40 basis points for retail electric and 50 basis points for firm natural gas for the twelve months ended Dec. 31, 2016.

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

• NSP-Minnesota’s residential sales decreased as a result of lower use per customer, partially offset by customer additions. Commercial and industrial (C&I) sales declined primarily as a result of lower use by customers in the manufacturing and service industries.
• PSCo’s residential growth reflects an increased number of customers. The C&I decline was mainly due to lower sales to certain large customers in the manufacturing, mining, oil and gas industries. The decline was partially offset by an increase in the number of small C&I customers.
• SPS’ residential sales decline was primarily the result of lower use per customer, partially offset by an increased number of customers. The increase in C&I sales was driven by energy sector expansion in the Southeastern New Mexico, Permian Basin area as well as greater use by agricultural customers.
• NSP-Wisconsin’s residential sales decrease was primarily attributable to lower use per customer, partially offset by customer additions. The C&I decline was largely due to reduced sales to small customers. The overall decrease was partially offset by an increase in the number of C&I customers as well as greater use in the large C&I class for the oil and gas industries.

Weather-normalized Natural Gas Sales Decline — Year-To-Date (Excluding Leap Day)

• Across natural gas service territories, lower natural gas sales reflect a decline in customer use, partially offset by a slight increase in the number of customers.

Electric Margin — Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have minimal impact on electric margin. The following table details the electric revenues and margin:

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
(Millions of Dollars)	2016			2015			2016			2015
Electric revenues	$	2,291		$	2,170		$	9,500		$	9,276
Electric fuel and purchased power	(963		)	(893		)	(3,718		)	(3,763		)
Electric margin	$	1,328		$	1,277		$	5,782		$	5,513

The following table summarizes the components of the changes in electric margin:

	Three Months			Twelve Months
	Ended Dec. 31			Ended Dec. 31
(Millions of Dollars)	2016 vs. 2015			2016 vs. 2015
Retail rate increases ^(a)	$	57		$	190
Non-fuel riders	12			28
Estimated impact of weather, excluding decoupling in Minnesota	—			19
Transmission revenue, net of costs	2			14
Retail sales (decline) growth, excluding weather impact	(6		)	9
PSCo earnings test refunds	7			6
Conservation incentive	(5		)	3
Firm wholesale	(6		)	(12		)
Other, net	(10		)	12
Total increase in electric margin	$	51		$	269

^(a)	Increase is primarily due to interim rates in Minnesota (net of estimated provision for refund) and final rates in Wisconsin and New Mexico.

Natural Gas Margin — Total natural gas expense tends to vary with changing sales requirements and the cost of natural gas purchases. Due to the design of purchased natural gas cost recovery mechanisms for sales to retail customers, fluctuations in the cost of natural gas has minimal impact on natural gas margin. The following table details natural gas revenues and margin:

	Three Months Ended Dec. 31						Twelve Months Ended Dec. 31
(Millions of Dollars)	2016			2015			2016			2015
Natural gas revenues	$	485		$	456		$	1,531		$	1,672
Cost of natural gas sold and transported	(263		)	(240		)	(733		)	(905		)
Natural gas margin	$	222		$	216		$	798		$	767

The following table summarizes the components of the changes in natural gas margin:

	Three Months			Twelve Months
	Ended Dec. 31			Ended Dec. 31
(Millions of Dollars)	2016 vs. 2015			2016 vs. 2015
Retail rate increases ^(a)	$	5		$	36
Conservation and demand side management (DSM) program revenues (offset by expenses)	2			8
Estimated impact of weather	—			(5		)
Infrastructure and integrity riders, partially offset in O&M expenses	—			(5		)
Other, net	(1		)	(3		)
Total increase in natural gas margin	$	6		$	31
^(a) Increase is primarily related to final natural gas rates in Colorado.

O&M Expenses — O&M expenses decreased $21.4 million, or 3.7 percent, for the fourth quarter of 2016 and $3.1 million, or 0.1 percent, for 2016 compared with the same periods in 2015. The fourth quarter decline was driven by lower employee benefit costs and deferral of certain expenses associated with the Texas 2016 electric rate case.

Conservation and DSM Program Expenses — Conservation and DSM program expenses increased $8.1 million, or 13.6 percent, for the fourth quarter of 2016 and $20.1 million, or 8.9 percent, for 2016 compared with the same periods in 2015. Increases were primarily attributable to more customer participation in DSM programs. Higher conservation and DSM program expenses are generally offset by higher revenues due to recovery mechanisms.

Depreciation and Amortization — Depreciation and amortization increased $35.4 million, or 11.9 percent, for the fourth quarter of 2016 and $178.7 million, or 15.9 percent, for 2016 compared with the same periods in 2015. Increases were primarily attributable to capital investments, including Pleasant Valley and Border Wind Farms, reduction of the excess depreciation reserve in Minnesota and recognition of the Department of Energy (DOE) settlement credits in 2015.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $8.9 million, or 7.2 percent, for the fourth quarter of 2016 and $20.4 million, or 4.0 percent, for 2016 compared with the same periods in 2015. The year-to-date increase was primarily due to higher property taxes in Minnesota, excluding the impact of the proposed tax deferral in the settlement agreement in the Minnesota 2016 multi-year electric rate case.

Allowance for Funds Used During Construction (AFUDC), Equity and Debt — AFUDC increased $0.2 million for the fourth quarter of 2016 and $5.4 million for 2016 compared with the same periods in 2015. Increases were primarily due to the expansion of transmission facilities and other capital expenditures.

Interest Charges — Interest charges increased $8.1 million, or 5.3 percent, for the fourth quarter of 2016 and $51.6 million, or 8.7 percent, for 2016 compared with the same periods in 2015. Increases were related to higher long-term debt levels to fund capital investments, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense decreased $0.5 million for the fourth quarter of 2016 compared with the same period in 2015. The decrease was primarily due to higher tax expense for unrecognized tax benefits recorded in 2015, increased wind production tax credits in 2016 and higher prior year valuation allowances. These were partially offset by higher pretax earnings in 2016, higher tax benefit for permanent plant-related adjustments (e.g. AFUDC-equity) in 2015, additional research and experimentation credits in 2015 and a tax benefit for a carryback claim in 2015. The ETR was 32.5 percent for the fourth quarter of 2016 compared with 34.5 percent for the same period in 2015. The lower ETR in 2016 is primarily due to the adjustments referenced above.

Income tax expense increased $38.5 million for 2016 compared with 2015. The increase in income tax expense was primarily due to higher pretax earnings in 2016, partially offset by increased wind production tax credits in 2016. The ETR was 34.1 percent for 2016 compared with 35.5 percent for 2015. The lower ETR in 2016 is primarily due to the wind production tax credits in 2016.

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

Following is the capital structure of Xcel Energy:

	As of Dec. 31, 2016				As of Dec. 31, 2015
			Percentage of				Percentage of
(Billions of Dollars)	Capital Structure		Total Capitalization		Capital Structure		Total Capitalization
Current portion of long-term debt	$	0.3	1	%	$	0.7	3	%
Short-term debt	0.4		2		0.8		3
Long-term debt	14.2		55		12.5		51
Total debt	14.9		58		14.0		57
Common equity	11.0		42		10.6		43
Total capitalization	$	25.9	100	%	$	24.6	100	%

Credit Facilities — As of Jan. 30, 2017, 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.	$	1,000	$	130	$	870	$	—	$	870
PSCo	700		251		449		—		449
SPS	400		109		291		1		292
NSP-Minnesota	500		139		361		1		362
NSP-Wisconsin	150		88		62		1		63
Total	$	2,750	$	717	$	2,033	$	3	$	2,036
^(a) These credit facilities expire in June 2021.
^(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. 30, 2017, 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+
	NSP-Minnesota	A2	A-	A
	NSP-Wisconsin	A2	A-	A
	PSCo	A3	A-	A
	SPS	Baa1	A-	BBB+
Senior Secured Debt	NSP-Minnesota	Aa3	A	A+
	NSP-Wisconsin	Aa3	A	A+
	PSCo	A1	A	A+
	SPS	A2	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

2017 Planned Financing Activity — Xcel Energy Inc. and its utility subsidiaries’ 2017 financing plans reflect the following:

• Xcel Energy Inc. plans to issue approximately $300 million of senior unsecured bonds;
• NSP-Minnesota plans to issue approximately $600 million of first mortgage bonds;
• NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds;
• PSCo plans to issue approximately $400 million of first mortgage bonds; and
• SPS plans to issue approximately $250 million of first mortgage bonds.

2016 Financing Activity — During 2016, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances:

• Xcel Energy Inc. issued $400 million of 2.4 percent senior notes due March 15, 2021 and $350 million of 3.3 percent senior notes due June 1, 2025;
• NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046;
• PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046;
• SPS issued $300 million of 3.4 percent first mortgage bonds due Aug. 15, 2046; and
• Xcel Energy Inc. issued $300 million of 2.6 percent senior notes due March 15, 2022 and $500 million of 3.35 percent senior notes due Dec. 1, 2026.

Note 4. Rates and Regulation

NSP-Minnesota – Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three-year electric rate case with the Minnesota Public Utilities Commission (MPUC). The rate case is based on a requested ROE of 10.0 percent and a 52.50 percent equity ratio. In December 2015, the MPUC approved interim rates for 2016. The request is detailed in the table below:

Request (Millions of Dollars)	2016			2017			2018
Rate request	$	194.6		$	52.1		$	50.4
Increase percentage	6.4		%	1.7		%	1.7		%
Interim request	$	163.7		$	44.9		N/A
Rate base	$	7,800		$	7,700		$	7,700

Settlement Agreement
In August 2016, NSP-Minnesota and various parties reached a settlement which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC. Key terms of the settlement are listed below:

• Four-year period covering 2016-2019;
• Incremental rate increases of $74.99 million for 2016, $59.86 million for 2017, $0 million for 2018 and $50.12 million for 2019, subject to an annual sales true-up as detailed below:
  • 2016 weather-normalized actuals used to set final 2016 rates, no cap;
  • 2016-2019 full decoupling for residential and non-demand metered commercial classes with a 3 percent cap; and
  • 2017-2019 annual true-up for non-decoupled classes with a 3 percent cap.

• ROE of 9.2 percent and an equity ratio of 52.5 percent;
• Nuclear related costs will not be considered provisional;
• Continued use of all existing riders, however no new riders may be utilized during the four-year term;
• Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019;
• Four-year stay out provision for rate cases;
• Property tax true-up mechanism for 2017-2019; and
• Capital expenditure true-up mechanism for 2016-2019.

The schedule for the Minnesota rate case is listed below:

• Administrative law judge (ALJ) report — March 3, 2017; and
• MPUC decision — June 2017.

A current liability that is consistent with the settlement and represents NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of Dec. 31, 2016.

PSCo – Decoupling Filing — In July 2016, PSCo filed a request with the Colorado Public Utilities Commission (CPUC) to approve a partial decoupling mechanism for a five year period, effective Jan. 1, 2017. The proposed decoupling adjustment would allow PSCo to adjust annual revenues based on changes in weather normalized average use per customer for the residential and small C&I classes. The proposed decoupling mechanism is symmetric and may result in potential refunds to customers if there were an increase in average use per customer. PSCo did not request that revenue be adjusted as a result of weather related sales fluctuations.

In January 2017, the CPUC Staff (Staff) and various intervenors, including the Office of Consumer Counsel (OCC), filed direct testimony.

• The Staff recommended a portion of PSCo’s request be approved and suggested the CPUC should lower PSCo’s ROE by 30 basis points to account for lower risk associated with annual revenues, if the full proposal were approved;
• The OCC opposed PSCo’s decoupling request; and
• Other intervening parties generally supported PSCo’s proposal, but recommended various modifications, such as the use of actual sales data instead of weather-normalized sales.

The remaining key dates in the procedural schedule are as follows:

• Rebuttal and cross answer testimony — Feb. 10, 2017;
• Hearings — Feb. 21-24, 2017; and
• A CPUC decision is expected in April 2017.

SPS – Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the Public Utility Commission of Texas (PUCT) requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a historic test year ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In September 2016, SPS revised its requested rate increase to $61.5 million and along with recovery of rate case expenses made for an overall revised request of $65.5 million.

In December 2016, SPS reached an unopposed settlement that resolves all issues in the rate case. The following table reflects the total estimated impact:

(Millions of Dollars)	Settlement
Base rate increase, retroactive to July 20, 2016	$	35.2
Power factor revenues ^(a)	12.6
Rate case expenses to be addressed in a separate proceeding	4.0
Total estimated impact	$	51.8

^(a)	SPS’ request assumed customers would adjust their power factors, which would reduce revenue. To the extent power factor revenues are less than $12.6 million, a mechanism will be established to ensure SPS recovers this amount and effectively offset lower anticipated power factor charges.

Additional key terms are as follows:

• SPS’ next transmission cost recovery factor application will have a cap of $19 million in additional annual revenue and parties will make reasonable efforts to obtain PUCT approval within 100 days of SPS’ initial filing;
• No disallowance of SPS’ requested capital additions; and
• No restrictions on filing future rate cases or rate riders.

Pursuant to legislation passed in Texas in 2015, the final rates established in the case will be effective retroactive to July 20, 2016. In December 2016, an ALJ approved interim rates, effective as of Dec. 10, 2016. In the fourth quarter of 2016, SPS deferred certain costs associated with this rate case. In January 2017, the PUCT approved the settlement and no refund of interim rates was necessary. SPS expects to file a surcharge to recover the additional revenue associated with final rates, for the period of July 20, 2016 through Dec. 9, 2016, by the third quarter of 2017.

SPS – New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the New Mexico Public Regulation Commission (NMPRC) for an increase in base rates of approximately $41.4 million, representing a total revenue increase of approximately 10.9 percent. The rate filing is based on a future test year ending June 30, 2018, a requested return on equity of 10.1 percent, an equity ratio of 53.97 percent and an electric rate base of approximately $832 million.

SPS has excluded fuel and purchased power costs from base rates. This base rate case also takes into account the decline in sales of 380 megawatts in 2017 from certain wholesale customers and seeks to adjust the service life of SPS’ Tolk power plant.

The key dates in the procedural schedule are as follows:

• Deadline for settlement — Feb. 28, 2017;
• Staff and intervenor testimony — April 14, 2017;
• Rebuttal testimony — May 3, 2017;
• Hearings — May 15, 2017; and
• An NMPRC decision and implementation of final rates is anticipated in the second half of 2017.

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

Xcel Energy 2017 Earnings Guidance — Xcel Energy’s 2017 GAAP and ongoing earnings guidance is $2.25 to $2.35 per share.^(a) Key assumptions related to 2017 earnings are detailed below:

• Constructive outcomes in all rate case and regulatory proceedings.
• Normal weather patterns are experienced for the year.
• Weather-normalized retail electric utility sales are projected to increase 0 percent to 0.5 percent.
• Weather-normalized retail firm natural gas sales are projected to increase 0 percent to 0.5 percent.
• Capital rider revenue is projected to increase by $60 million to $70 million over 2016 levels.
• O&M expenses are projected to be flat.
• Depreciation expense is projected to increase approximately $165 million to $175 million over 2016 levels.
• Property taxes are projected to increase approximately $0 million to $10 million over 2016 levels.
• Interest expense (net of AFUDC — debt) is projected to increase $20 million to $30 million over 2016 levels.
• AFUDC — equity is projected to increase approximately $0 million to $10 million from 2016 levels.
• The ETR is projected to be approximately 32 percent to 34 percent.
• Average common stock and equivalents are projected to be approximately 509 million shares.

^(a)	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 diluted EPS to corresponding GAAP diluted 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 4 percent to 6 percent;

• Deliver annual dividend increases of 5 percent to 7 percent;

• Target a dividend payout ratio of 60 percent to 70 percent; and

• Maintain senior unsecured debt credit ratings in the BBB+ to A range.

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.

Note 6. 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, for reporting of results to the Board of Directors and when communicating its earnings outlook to analysts and investors.

The following table provides a reconciliation of ongoing earnings to GAAP earnings (net income):

	Three Months Ended Dec. 31				Twelve Months Ended Dec. 31
(Thousands of Dollars)	2016		2015		2016		2015
Ongoing earnings	$	227,477	$	209,025	$	1,123,379	$	1,063,635
Loss on Monticello LCM/EPU project	—		—		—		(79,150		)
GAAP earnings	$	227,477	$	209,025	$	1,123,379	$	984,485

Loss on Monticello LCM/EPU Project — In March 2015, the MPUC approved full recovery, including a return, on $415 million of the project costs, inclusive of AFUDC, but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment for years 2015 and beyond. As a result of this decision, Xcel Energy recorded a pre-tax charge of approximately $129 million, or $79 million net of tax, in the first quarter of 2015. Given the nature of this specific item, it has been excluded from ongoing earnings.

XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (Unaudited)
(amounts in thousands, except per share data)
	Three Months Ended Dec. 31
	2016			2015
Operating revenues:
Electric and natural gas	$	2,775,424		$	2,626,118
Other	19,227			19,703
Total operating revenues	2,794,651			2,645,821
Net income	$	227,477		$	209,025
Weighted average diluted common shares outstanding	509,421			508,738
Components of EPS — Diluted
Regulated utility	$	0.48		$	0.44
Xcel Energy Inc. and other	(0.04		)	(0.03		)
GAAP and ongoing diluted EPS ^(a)	$	0.45		$	0.41
	Twelve Months Ended Dec. 31
	2016			2015
Operating revenues:
Electric and natural gas	$	11,031,193		$	10,948,067
Other	75,727			76,419
Total operating revenues	11,106,920			11,024,486
Net income	$	1,123,379		$	984,485
Weighted average diluted common shares outstanding	509,465			508,168
Components of EPS — Diluted
Regulated utility	$	2.35		$	2.21
Xcel Energy Inc. and other	(0.15		)	(0.11		)
Ongoing diluted EPS ^(a)	2.21			2.09
Loss on Monticello LCM/EPU project ^(b)	—			(0.16		)
GAAP diluted EPS ^(a)	$	2.21		$	1.94
Book value per share	$	21.73		$	20.89
^(a) Amounts may not add due to rounding
^(b) See Note 6.