Xcel Energy 2015 Year End Earnings Report

Xcel Energy Inc. (NYSE:XEL) today reported 2015 GAAP earnings of $984
million, or $1.94 per share, compared with 2014 GAAP earnings of $1,021
million, or $2.03 per share.

Ongoing earnings, which exclude adjustments for certain items, were
$2.09 per share for 2015 compared with $2.03 per share in 2014. Ongoing
earnings increased primarily due to rate increases in various
jurisdictions, non-fuel riders, a lower earnings test refund in Colorado
and a decline in operating and maintenance expenses. These positive
factors were partially offset by the impact of negative weather (seven
cents per share) as well as higher depreciation, property taxes,
interest charges and lower allowance for fund used for construction.

This is the eleventh consecutive year, Xcel Energy has met or exceeded
its earnings guidance, and the twelfth consecutive year the company has
increased its dividend.

“I am pleased with our 2015 results,” stated Ben Fowke, Chairman,
President and Chief Executive Officer. “We delivered earnings within our
guidance range despite negative weather and certain regulatory
challenges. We were able to accomplish this by reducing O&M expenses and
taking other management actions.”

“We are proud of our long track record of delivering financial results
that are worthy of the trust our investors place in us,” said Fowke.
“Strong fundamentals, a committed workforce and solid, consistent
performance are the hallmark of Xcel Energy.”

Xcel Energy reaffirms its 2016 ongoing earnings guidance of $2.12 to
$2.27 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 GAAP EPS:

			Three Months Ended Dec. 31								Twelve Months Ended Dec. 31
Diluted Earnings (Loss) Per Share			2015				2014				2015					2014
Ongoing diluted EPS			$	0.41			$	0.39			$	2.09				$	2.03
Loss on Monticello life cycle management/extended power uprate project (a)				—				—				(0.16	)				—
GAAP diluted EPS (b)			$	0.41			$	0.39			$	1.94				$	2.03
(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:			(888) 542-1139
International Dial-In:			(719) 457-2084
Conference ID:			534445

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. 28 through 10:59 p.m. CST on Jan. 29.

Replay Numbers
US Dial-In:			(888) 203-1112
International Dial-In:			(719) 457-0820
Access Code:			534445

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 2016 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, 2014, 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
			2015					2014					2015					2014
Operating revenues
Electric			$	2,170,183				$	2,250,191				$	9,275,986				$	9,465,890
Natural gas				455,935					657,274					1,672,081					2,142,738
Other				19,703					21,163					76,419					77,507
Total operating revenues				2,645,821					2,928,628					11,024,486					11,686,135
Operating expenses
Electric fuel and purchased power				893,390					1,021,644					3,762,953					4,210,142
Cost of natural gas sold and transported				239,685					438,406					904,794					1,372,479
Cost of sales — other				9,800					9,569					36,216					34,352
Operating and maintenance expenses				583,577					620,241					2,329,670					2,334,379
Conservation and demand side management program expenses				59,419					78,220					224,679					301,772
Depreciation and amortization				296,703					262,400					1,124,524					1,019,045
Taxes (other than income taxes)				122,237					106,898					511,675					465,836
Loss on Monticello life cycle management/extended power uprate project				—					—					129,463					—
Total operating expenses				2,204,811					2,537,378					9,023,974					9,738,005
Operating income				441,010					391,250					2,000,512					1,948,130
Other (expense) income, net				(348	)				609					5,400					5,296
Equity earnings of unconsolidated subsidiaries				10,030					7,501					34,390					30,151
Allowance for funds used during construction — equity				15,208					20,898					55,936					89,750
Interest charges and financing costs
Interest charges — includes other financing costs of $6,357, $5,842, $24,175, and $22,986, respectively				153,554					144,895					595,282					566,608
Allowance for funds used during construction — debt				(6,908	)				(8,793	)				(26,248	)				(38,402	)
Total interest charges and financing costs				146,646					136,102					569,034					528,206
Income before income taxes				319,254					284,156					1,527,204					1,545,121
Income taxes				110,229					87,817					542,719					523,815
Net income			$	209,025				$	196,339				$	984,485				$	1,021,306
Weighted average common shares outstanding:
Basic				508,312					506,411					507,768					503,847
Diluted				508,738					506,799					508,168					504,117
Earnings per average common share:
Basic			$	0.41				$	0.39				$	1.94				$	2.03
Diluted				0.41					0.39					1.94					2.03
Cash dividends declared per common share			$	0.32				$	0.30				$	1.28				$	1.20

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		2015				2014				2015				2014
Public Service Company of Colorado (PSCo)		$	0.16			$	0.18			$	0.92			$	0.90
NSP-Minnesota			0.20				0.17				0.85				0.80
Southwestern Public Service Company (SPS)			0.04				0.03				0.25				0.26
NSP-Wisconsin			0.03				0.03				0.15				0.14
Equity earnings of unconsolidated subsidiaries			0.01				0.01				0.04				0.04
Regulated utility			0.44				0.42				2.21				2.14
Xcel Energy Inc. and other			(0.03	)			(0.03	)			(0.11	)			(0.11	)
Ongoing diluted EPS (a)			0.41				0.39				2.09				2.03
Loss on Monticello life cycle management (LCM)/extended power uprate (EPU) project (b)			—				—				(0.16	)			—
GAAP diluted EPS (a)		$	0.41			$	0.39			$	1.94			$	2.03
(a) Amounts may not add due to rounding.
(b) See Note 6.

PSCo — PSCo’s ongoing earnings increased $0.02 per share
for 2015. Higher revenue primarily due to the Clean Air Clean Jobs Act
(CACJA) rider (partially offset by an electric base rate decrease), as
well as a natural gas rate increase (interim, subject to refund)
effective in October 2015, lower estimated electric earnings test
refunds and the positive impact of weather. These positive factors were
partially offset by higher property taxes, depreciation, operating and
maintenance (O&M) expenses, interest charges and lower allowance for
funds used during construction (AFUDC).

NSP-Minnesota — NSP-Minnesota’s ongoing earnings increased
$0.05 per share for 2015. Ongoing earnings were positively impacted by
electric rate increases in Minnesota, North Dakota and South Dakota, and
lower O&M expenses. These positive factors were partially offset by
unfavorable weather, sales decline, higher depreciation, increased
interest charges, property taxes and lower AFUDC.

SPS — SPS’ ongoing earnings decreased $0.01 per share for
2015. Although Texas electric rates rose as a result of the prior year
rate case, this was reduced by the negative impact of the 2015 case. The
net increase in electric rates was more than offset by additional
depreciation, higher O&M expenses and lower AFUDC.

NSP-Wisconsin — NSP-Wisconsin’s ongoing earnings increased
$0.01 per share for 2015. Higher electric revenues primarily driven by
an electric rate increase and lower O&M expenses were partially offset
by higher depreciation and lower natural gas margins.

The following table summarizes significant components contributing to
the changes in 2015 EPS compared with the same period in 2014:

Diluted Earnings (Loss) Per Share			Three Months Ended Dec. 31					Twelve Months Ended Dec. 31
2014 GAAP and ongoing diluted EPS			$	0.39				$	2.03
Components of change — 2015 vs. 2014
Higher electric margins				0.06					0.31
Lower conservation and demand side management (DSM) program expenses				0.02					0.09
Lower O&M expenses				0.04					0.01
Higher depreciation and amortization				(0.04	)				(0.13	)
Lower AFUDC — equity				(0.01	)				(0.07	)
Higher effective tax rate (ETR)				(0.02	)				(0.06	)
Higher taxes (other than income taxes)				(0.02	)				(0.06	)
Higher interest charges				(0.01	)				(0.03	)
Other, net				—					0.01
2015 ongoing diluted EPS (a)				0.41					2.09
Loss on Monticello LCM/EPU project (b)				—					(0.16	)
2015 GAAP diluted EPS (a)			$	0.41				$	1.94

ROE — 2015			PSCo				NSP-Minnesota				SPS				NSP-Wisconsin				Operating Companies (c)				Xcel Energy (c)
2015 ongoing ROE			9.33	%			8.72	%			7.56	%			10.45	%			8.91	%			10.22	%
Loss on Monticello LCM/EPU project (b)			—				(1.49	)			—				(0.42	)			(0.62	)			(0.76	)
2015 GAAP ROE			9.33	%			7.23	%			7.56	%			10.03	%			8.29	%			9.46	%
ROE — 2014			PSCo				NSP-Minnesota				SPS				NSP-Wisconsin				Operating Companies (c)				Xcel Energy (c)
2014 ongoing and GAAP ROE			9.40	%			8.82	%			8.88	%			10.85	%			9.18	%			10.33	%
(a) Amounts may not add due to rounding.
(b) See Note 6.
(c) Excluding the impact of negative/positive weather, the Operating Companies and Xcel Energy's ongoing ROEs equate to 9.07 percent and 10.40 percent, respectively, for 2015 and 9.06 percent and 10.18 percent, respectively, for 2014.

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 cooling degree-day, and each degree of
temperature below 65° Fahrenheit is counted as one heating degree-day.
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
			2015 vs. Normal				2014 vs. Normal				2015 vs. 2014				2015 vs. Normal				2014 vs. Normal				2015 vs. 2014
HDD			(14.1	)%			1.8	%			(15.7	)%			(7.9	)%			7.8	%			(14.8	)%
CDD (a)			N/A				N/A				N/A				6.2				(2.6	)			10.3
THI (a)			N/A				N/A				N/A				(2.3	)			(11.9	)			14.1
(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
			2015 vs. Normal					2014 vs. Normal				2015 vs. 2014					2015 vs. Normal					2014 vs. Normal				2015 vs. 2014
Retail electric			$	(0.016	)			$	—			$	(0.016	)			$	(0.020	)			$	0.010			$	(0.030	)
Firm natural gas				(0.011	)				0.001				(0.012	)				(0.018	)				0.019				(0.037	)
Total			$	(0.027	)			$	0.001			$	(0.028	)			$	(0.038	)			$	0.029			$	(0.067	)

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

			Three Months Ended Dec. 31
			PSCo				NSP-Minnesota					SPS				NSP-Wisconsin				Xcel Energy
Actual
Electric residential (a)			3.1	%			(4.0		)%			(0.6	)%			(10.5	)%			(1.4	)%
Electric commercial and industrial			(1.5	)			(1.5		)			1.5				(2.3	)			(0.9	)
Total retail electric sales			(0.1	)			(2.2		)			1.0				(4.7	)			(1.0	)
Firm natural gas sales			(1.7	)			(20.9		)			N/A				(25.6	)			(9.2	)
			Three Months Ended Dec. 31
			PSCo				NSP-Minnesota					SPS				NSP-Wisconsin				Xcel Energy
Weather-normalized
Electric residential (a)			2.0	%			0.9	%				(0.7	)%			(3.9	)%			0.7	%
Electric commercial and industrial			(1.8	)			(1.0	)				1.7				(1.5	)			(0.7	)
Total retail electric sales			(0.6	)			(0.5	)				1.1				(2.2	)			(0.3	)
Firm natural gas sales			(1.5	)			(1.2	)				N/A				(5.4	)			(1.7	)
			Twelve Months Ended Dec. 31
			PSCo				NSP-Minnesota					SPS				NSP-Wisconsin				Xcel Energy
Actual
Electric residential (a)			1.1	%			(3.2		)%			(0.4	)%			(6.1	)%			(1.4	)%
Electric commercial and industrial			(0.4	)			(0.6		)			0.3				0.4				(0.2	)
Total retail electric sales			0.1				(1.4		)			0.1				(1.5	)			(0.6	)
Firm natural gas sales			(6.6	)			(16.6		)			N/A				(16.4	)			(10.5	)
			Twelve Months Ended Dec. 31
			PSCo				NSP-Minnesota					SPS				NSP-Wisconsin				Xcel Energy
Weather-normalized
Electric residential (a)			0.4	%			(0.7		)%			0.6	%			(2.8	)%			(0.3	)%
Electric commercial and industrial			(0.9	)			(0.2		)			0.7				0.8				(0.1	)
Total retail electric sales			(0.5	)			(0.4		)			0.5				(0.3	)			(0.2	)
Firm natural gas sales			(2.0	)			(1.1		)			N/A				(1.7	)			(1.7	)
(a) Extreme weather variations and additional factors such as windchill and cloud cover may not be reflected in weather-normalized and actual growth estimates.

Weather-normalized Electric 2015 Growth (Decline)

• PSCo’s residential growth was primarily the result of customer
  additions, partially offset by lower use per customer. Commercial and
  industrial (C&I) decline was primarily due to reduced sales to certain
  large manufacturing customers and/or those that support the fracking
  industry.
• NSP-Minnesota’s residential decrease was due to lower use per
  customer, partially offset by an increase in customer additions. C&I
  electric sales decreased as a result of lower use by large and small
  customers (e.g., services, retail trade, finance insurance and real
  estate industries), partially offset by higher use by certain large
  customers in the petroleum and food processing industries. The decline
  was partially reduced by an increase in the number of customers in
  both the small and large classes.
• SPS’ residential growth reflects an increased number of customers. C&I
  also had an increase in customers, primarily in the oil and gas
  exploration and production industries. However, this was partially
  offset by reduced activity per customer within these industries, as
  well as less irrigation by agricultural customers due to wet weather.
• NSP-Wisconsin’s residential decline was primarily attributable to
  lower use per customer, partially offset by customer additions. C&I
  electric sales growth was largely due to strong sales to large
  customers primarily in the oil and gas industries.

Weather-normalized Natural Gas 2015 Decline

• Across natural gas service territories, lower natural gas sales
  reflect a decline in customer use.

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)			2015					2014					2015					2014
Electric revenues			$	2,170				$	2,250				$	9,276				$	9,466
Electric fuel and purchased power				(893	)				(1,022	)				(3,763	)				(4,210	)
Electric margin			$	1,277				$	1,228				$	5,513				$	5,256

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

(Millions of Dollars)		Three Months Ended Dec. 31 2015 vs. 2014				Twelve Months Ended Dec. 31 2015 vs. 2014
Retail rate increases (a)		$	21			$	101
Colorado CACJA non-fuel rider			20				94
PSCo earnings test refunds			13				74
Transmission revenue, net of costs			19				47
Non-fuel riders (b)			8				20
Conservation and DSM program revenues (offset by expenses)			(16	)			(62	)
Estimated impact of weather			(12	)			(23	)
Other, net			(4	)			6
Total increase in electric margin		$	49			$	257
(a) Increase due to rate proceedings in Minnesota, South Dakota, Texas, North Dakota, New Mexico and Wisconsin. These increases were partially offset by a decline in Colorado retail base rates, which was more than offset by increased CACJA rider revenue.
(b) Primarily related to the Transmission Cost Recovery rider in Minnesota.

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)			2015					2014					2015					2014
Natural gas revenues			$	456				$	657				$	1,672				$	2,143
Cost of natural gas sold and transported				(240	)				(438	)				(905	)				(1,372	)
Natural gas margin			$	216				$	219				$	767				$	771

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

(Millions of Dollars)			Three Months Ended Dec. 31 2015 vs. 2014					Twelve Months Ended Dec. 31 2015 vs. 2014
Estimated impact of weather			$	(10	)			$	(30	)
Conservation and DSM program revenues (offset by expenses)				(2	)				(13	)
Infrastructure and integrity riders, partially offset in O&M expenses				5					30
Purchased gas adjustment				—					5
Retail rate increases (Colorado, interim, subject to refund)				4					4
Total decrease in natural gas margin			$	(3	)			$	(4	)

O&M Expenses — O&M expenses decreased $36.7 million,
or 5.9 percent, for the fourth quarter of 2015 and $4.7 million, or 0.2
percent, for 2015 compared with the same periods in 2014. The following
table summarizes the changes in O&M expenses:

(Millions of Dollars)			Three Months Ended Dec. 31 2015 vs. 2014					Twelve Months Ended Dec. 31 2015 vs. 2014
Nuclear plant operations			$	(15	)			$	(22	)
Transmission costs				(2	)				(4	)
Labor and contract labor				3					14
Plant generation costs				(12	)				1
Other, net				(11	)				6
Total decrease in O&M expenses			$	(37	)			$	(5	)

Changes in annual O&M expenses were due to the following:

• Nuclear expense decreased primarily driven by operational efficiencies
  and lower amortization of prior outages; and
• Labor and contract labor increased as a result of various projects and
  initiatives to improve business processes.

Conservation and DSM Program Expenses — Conservation and
DSM program expenses decreased $18.8 million, or 24.0 percent, for the
fourth quarter of 2015 and $77.1 million, or 25.5 percent, for 2015
compared with the same periods in 2014. The decreases were primarily
attributable to lower electric and gas recovery rates at NSP-Minnesota
and PSCo. Lower conservation and DSM program expenses are generally
offset by lower revenues.

Depreciation and Amortization — Depreciation and
amortization increased $34.3 million, or 13.1 percent, for the fourth
quarter of 2015 and $105.5 million, or 10.4 percent, for 2015 compared
with the same periods in 2014. Increases were primarily attributed to
capital investments and lower amortization of the excess depreciation
reserve in Minnesota, partially offset by Minnesota’s amortization of
the Department of Energy settlement.

Taxes (Other Than Income Taxes) — Taxes (other than income
taxes) increased $15.3 million, or 14.3 percent, for the fourth quarter
of 2015 and $45.8 million, or 9.8 percent, for 2015 compared with the
same periods in 2014. Increases were due to higher property taxes
primarily in Colorado and Minnesota.

AFUDC, Equity and Debt — AFUDC decreased $7.6 million for
the fourth quarter of 2015 and $46.0 million for 2015 compared with the
same periods in 2014. Decreases were primarily due to the implementation
of the CACJA rider, facilitating earlier and alternative recovery of
construction costs.

Interest Charges — Interest charges increased $8.7
million, or 6.0 percent, for the fourth quarter of 2015 and $28.7
million, or 5.1 percent, for 2015 compared with the same periods in
2014. Increases were primarily due to higher long-term debt levels,
partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased $22.4 million
for the fourth quarter of 2015 compared with the same period in 2014.
The increase was primarily due to higher pretax earnings in 2015 and a
higher tax benefit for a carryback claim in 2014. The effective tax rate
(ETR) was 34.5 percent for the fourth quarter of 2015 compared with 30.9
percent for the same period in 2014. The lower ETR for 2014 was
primarily due to the tax benefit for the carryback.

Income tax expense increased $18.9 million for 2015 compared with 2014.
The increase was primarily due to a higher tax benefit for a carryback
claim in 2014 and decrease in permanent plant-related deductions (e.g.,
AFUDC-equity) in 2015. The ETR was 35.5 percent for 2015 compared with
33.9 percent for 2014. The difference between periods was primarily due
to the permanent plant-related deductions and the tax benefit for a
carryback claim in 2014.

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

Following is the capital structure of Xcel Energy:

			As of December 31, 2015								As of December 31, 2014
(Billions of Dollars)			Capital Structure				Percentage of Total Capitalization				Capital Structure				Percentage of Total Capitalization
Current portion of long-term debt			$	0.7			3	%			$	0.3			1	%
Short-term debt				0.8			3					1.0			4
Long-term debt				12.5			51					11.5			50
Total debt				14.0			57					12.8			55
Common equity				10.6			43					10.2			45
Total capitalization			$	24.6			100	%			$	23.0			100	%

Credit Facilities — As of Jan. 25,
2016, 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			$	554			$	446			$	—			$	446
PSCo				700				158				542				1				543
SPS				400				91				309				—				309
NSP-Minnesota				500				371				129				1				130
NSP-Wisconsin				150				38				112				1				113
Total			$	2,750			$	1,212			$	1,538			$	3			$	1,541
(a) These credit facilities mature in October 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).

As of Jan. 25, 2016, the following represents the credit ratings
assigned to Xcel Energy Inc. and its utility subsidiaries:

Company

Credit Type

Moody’s

Standard & Poor’s

Fitch

Xcel Energy Inc.

Senior Unsecured Debt

A3

BBB+

BBB+

Xcel Energy Inc.

Commercial Paper

P-2

A-2

F2

NSP-Minnesota

Senior Unsecured Debt

A2

A-

A

NSP-Minnesota

Senior Secured Debt

Aa3

A

A+

NSP-Minnesota

Commercial Paper

P-1

A-2

F2

NSP-Wisconsin

Senior Unsecured Debt

A2

A-

A

NSP-Wisconsin

Senior Secured Debt

Aa3

A

A+

NSP-Wisconsin

Commercial Paper

P-1

A-2

F2

PSCo

Senior Unsecured Debt

A3

A-

A

PSCo

Senior Secured Debt

A1

A

A+

PSCo

Commercial Paper

P-2

A-2

F2

SPS

Senior Unsecured Debt

Baa1

A-

BBB+

SPS

Senior Secured Debt

A2

A

A-

SPS

Commercial Paper

P-2

A-2

F2

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

Capital Expenditures — The actual and current estimated
base capital expenditure programs of Xcel Energy Inc. and its
subsidiaries for the years 2015 through 2020 are shown in the table
below.

			Actual				Base Capital Forecast
(Millions of Dollars)			2015				2016				2017				2018				2019				2020				2016 - 2020 Total
By Subsidiary
NSP-Minnesota			$	1,753			$	1,290			$	1,050			$	1,215			$	1,245			$	1,125			$	5,925
PSCo				944				975				940				960				1,030				1,070				4,975
SPS				602				560				725				640				520				450				2,895
NSP-Wisconsin				230				225				250				295				265				285				1,320
Other				—				10				10				10				10				10				50
Total capital expenditures			$	3,529			$	3,060			$	2,975			$	3,120			$	3,070			$	2,940			$	15,165
			Actual				Base Capital Forecast
(Millions of Dollars)			2015				2016				2017				2018				2019				2020				2016 - 2020 Total
By Function
Electric transmission			$	889			$	700			$	825			$	875			$	855			$	870			$	4,125
Electric distribution				639				645				775				790				915				940				4,065
Electric generation				1,230				835				510				565				470				465				2,845
Natural gas				368				390				335				395				390				400				1,910
Nuclear fuel				90				120				120				60				145				85				530
Minnesota Integrated Resource Plan renewables				—				—				120				250				110				—				480
Other				313				370				290				185				185				180				1,210
Total capital expenditures			$	3,529			$	3,060			$	2,975			$	3,120			$	3,070			$	2,940			$	15,165

In addition, Xcel Energy has potential incremental capital investment
opportunities that could increase the base capital forecast by $2.5
billion over the 2016-2020 timeframe. This would result in a total
capital forecast of $17.7 billion for 2016-2020.

The capital expenditure programs of Xcel Energy are subject to
continuing review and modification. Actual utility capital expenditures
may vary from the estimates due to changes in electric and natural gas
projected load growth, regulatory decisions, legislative initiatives,
reserve margin requirements, the availability of purchased power,
alternative plans for meeting long-term energy needs, compliance with
environmental requirements, renewable portfolio standards and merger,
acquisition and divestiture opportunities. The table above does not
include potential expenditures of Xcel Energy’s transmission-only
subsidiaries.

PSCo Natural Gas Reserves Investments — In January 2016,
PSCo filed a request with the CPUC for approval of a long-term natural
gas procurement and price hedging framework. Under the proposal a
wholly-owned subsidiary of PSCo, PSCo Gas Reserves Company (PGRCo), will
be formed to partner with Wexpro Development Company (Wexpro), a
subsidiary of Questar Corporation, to acquire, develop and operate
natural gas producing properties on a 50/50 joint basis, with production
recovered under cost of service pricing through PSCo’s Gas Cost
Adjustment. The CPUC has 240 days to review the proposed framework. If
approved, PGRCo may invest up to approximately $500 million in gas
properties over 10 years, which is not reflected in the current base
capital expenditures forecast.

The requested cost of service pricing formulas provide PGRCo and Wexpro
different risks and incentives. For PGRCo, the investment would include
all costs of property acquisition and development. The ROE would be
based on PSCo’s allowed ROE, adjusted up or down a maximum of 100 basis
points, based on the price of gas produced relative to market prices.

Following approval of the framework, PSCo and Wexpro will seek to
identify and acquire specific natural gas producing properties that
would be beneficial to PSCo’s gas customers, and seek CPUC approval of
these specific investments.

Financing — Xcel Energy issues debt and equity securities
to refinance retiring maturities, reduce short-term debt, fund capital
programs, infuse equity in subsidiaries, fund asset acquisitions and for
other general corporate purposes. Xcel Energy does not anticipate
issuing any equity to fund its base capital investment program for
2016-2020. The current estimated financing plans of Xcel Energy Inc. and
its subsidiaries for the years 2016 through 2020 are shown in the table
below.

(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations*						$		12,400
New Debt**								2,765
Equity								0
2016-2020 Capital Expenditures						$		15,165
Maturing Debt						$		4,165
* Net of dividend and pension funding.
** Reflects a combination of short and long-term debt.

During 2016, Xcel Energy Inc. and its utility subsidiaries anticipate
issuing the following:

• Xcel Energy Inc. plans to issue approximately $700 million of senior
  unsecured bonds;
• NSP-Minnesota plans to issue approximately $250 million of first
  mortgage bonds; and
• SPS plans to issue approximately $350 million of first mortgage bonds.

Financing plans are subject to change, depending on capital
expenditures, internal cash generation, market conditions and other
factors.

2015 Financing Activity — During 2015, Xcel Energy Inc.
and its utility subsidiaries completed the following bond issuances:

• PSCo issued $250 million of 2.9 percent first mortgage bonds due May
  15, 2025;
• Xcel Energy Inc. issued $250 million of 1.2 percent senior notes due
  June 1, 2017 and $250 million of 3.3 percent senior notes due June 1,
  2025;
• NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds
  due June 15, 2024;
• NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds
  due Aug. 15, 2020 and $300 million of 4.0 percent first mortgage bonds
  due Aug. 15, 2045; and
• SPS issued $200 million of 3.3 percent first mortgage bonds due June
  15, 2024.

Note 4. Rates and Regulation

NSP-Minnesota – Minnesota 2016 Multi-Year Electric Rate Case —
On Nov. 2, 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. 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

NSP-Minnesota also proposed a five-year alternative plan that would
extend the rate plan two additional years.

In addition, NSP-Minnesota has requested the MPUC encourage parties to
engage in a formal mediation type procedure as outlined by Minnesota’s
rate case statute which may streamline the settlement process.

In December 2015, the MPUC accepted the rate case and approved interim
rates for 2016. The MPUC deferred making a decision on incremental
interim rates for 2017 and indicated that NSP-Minnesota could bring back
its request in the fourth quarter of 2016. The MPUC also required
NSP-Minnesota to file supplemental direct testimony by Jan. 29, 2016,
addressing costs to complete the LCM at the Prairie Island nuclear plant.

The next steps in the procedural schedule are expected to be as follows:

• Intervenors' direct testimony — June 14, 2016;
• Rebuttal testimony — Aug. 9, 2016;
• Surrebuttal testimony — Sept. 16, 2016;
• Settlement conference — Sept. 26, 2016;
• Evidentiary hearing — Oct. 4-7, 2016;
• Administrative Law Judge (ALJ) report — Feb. 21, 2017; and
• MPUC order — June 1, 2017.

NSP-Wisconsin – Wisconsin 2016 Electric and Gas Rate Case —
In May 2015, NSP-Wisconsin filed a request with the Public
Service Commission of Wisconsin (PSCW) seeking an increase in annual
electric rates of $27.4 million, or 3.9 percent, and an increase in
natural gas rates of $5.9 million, or 5.0 percent, effective Jan. 1,
2016. The rate filing was based on a 2016 forecast test year, a ROE of
10.2 percent, an equity ratio of 52.5 percent and a forecasted average
rate base of approximately $1.2 billion for the electric utility and
$111.2 million for the natural gas utility.

In December 2015, the PSCW approved an electric rate increase of
approximately $7.6 million, or 1.1 percent, and a natural gas rate
increase of $4.2 million, or 3.6 percent, based on a 10.0 percent ROE
and an equity ratio of 52.5 percent. New rates went into effect in
January 2016. As shown below, NSP-Wisconsin received approximately 65
percent of the non-fuel and purchased power portion of its requested
electric rate increase and 71 percent of its requested natural gas rate
increase.

The major components of the requested rate increases and the PSCW's
approval are summarized as follows:

Electric Rate Request (Millions of Dollars)			NSP-Wisconsin Request					PSCW Approval
Capital investments			$	23.0				$	13.9
ROE & other capital structure adjustments				—					(3.8	)
Generation and transmission expenses (excluding fuel and purchased power)				37.2					42.7
O&M expenses				11.1					3.2
Sales forecast				(27.0	)				(27.0	)
Rate increase - non-fuel and purchased power				44.3					29.0
Rate reduction - fuel and purchased power				(16.9	)				(21.4	)
Total electric rate increase			$	27.4				$	7.6
Natural Gas Rate Request (Millions of Dollars)			NSP-Wisconsin Request					PSCW Approval
Capital investments			$	3.7				$	3.7
ROE & other capital structure adjustments				—					(0.4	)
O&M expenses				3.2					1.9
Environmental remediation expenses				2.9					2.9
Sales forecast				(3.9	)				(3.9	)
Total natural gas rate increase			$	5.9				$	4.2

PSCo – Colorado “Our Energy Future” Plan — The
proposal ties together innovative technology, economic development and
customer initiatives to give customers more control over their energy
use, prepare for the future energy demands of the state and keep rates
competitive. The key components of the plan include:

• Two Innovative Clean Technology pilot programs in partnership with
  leading companies, such as Panasonic Corporation, to address electric
  battery efficiency and reliability;
• Alignment of PSCo’s pricing in a more fair and equitable manner for
  Colorado customers;
• Introduction of Solar*Connect, a new, cost-based program that will
  offer customers a choice to sign up for 100 percent solar power and
  add an incremental 50 megawatts (MW) of solar generation;
• Investing in natural gas reserves to take advantage of historically
  low natural gas prices by locking in current costs to provide
  long-term predictable rates for our customers;
• Investigating up to 1,000 MW of additional renewable resources to be
  presented later this year for consideration by the CPUC; and
• Presenting an intelligent grid proposal later this year focusing on
  interactive meter technology that will improve customer choice and
  control of their energy use.

PSCo – Colorado 2015 Multi-Year Gas Rate Case — In
March 2015, PSCo filed a multi-year request with the CPUC to increase
Colorado retail natural gas base rates by $66.2 million over three
years. The request is based on a historic test year (HTY) ended June 30,
2014 adjusted for known and measurable expenses and capital additions
for each of the periods in the multi-year plan (MYP) and an equity ratio
of 56 percent. In addition, PSCo requested an extension of its pipeline
system integrity adjustment (PSIA) rider through 2020 to recover costs
associated with its pipeline integrity efforts. The rider would recover
incremental revenue of $42.8 million over three years.

In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel
(OCC) issued their base rate and PSIA recommendations. The Staff
recommended certain adjustments to the PSIA rider. The OCC stated that
the PSIA rider should expire on June 30, 2016 and any related costs be
included in base rates through a step increase.

In July 2015, PSCo filed rebuttal testimony with adjustments and
modified recovery between base rates and the PSIA rider. The revised
request is summarized below:

(Millions of Dollars)			2015					2016 Step					2017 Step
PSCo’s filed base rate request			$	40.5				$	7.6				$	18.1
Shift O&M expenses between PSIA and base rates				—					7.0					6.4
Rebuttal corrections and adjustments				—					—					(7.7	)
Total base rate increase			$	40.5				$	14.6				$	16.8
Incremental PSIA rider revenues				(0.1	)				14.7					21.7
Total revenue impact from rebuttal			$	40.4				$	29.3				$	38.5
Requested ROE				10.1	%				10.1	%				10.3	%
Rate base			$	1,260				$	1,310				$	1,360

In November 2015, the ALJ issued his recommended decision, which
reflected a 2014 HTY with a 13-month average rate base, the Cherokee
pipeline investment adjusted to year-end rate base, a ROE of 9.5 percent
and an equity ratio of 56.51 percent. In addition, the ALJ’s
recommendation included a three-year extension (2016 through 2018) of
the PSIA rider with all O&M expenses transferred to base rates as well
as certain other projects shifting between the PSIA rider and base
rates, beginning January 2016.

The ALJ also recommended that certain expenses, including property taxes
and damage prevention costs that exceed the 2014 HTY level, be deferred.
He further recommended a pension cost tracker and certain other deferral
related items.

The following table summarizes the estimated annual pre-tax impact of
the ALJ's recommended decision:

(Millions of Dollars)			2015					2016					2017
Total base rate increase			$	18.1				$	20.0				$	—
Incremental PSIA rider revenues				(0.2	)				(7.0	)				17.6
Expense deferrals				0.2					4.8					9.6
Estimated pre-tax impact			$	18.1				$	17.8				$	27.2

Interim rates, subject to refund, went into effect Oct. 1, 2015. PSCo
has recognized management’s best estimate of the potential customer
refund obligation.

On Jan. 27, 2016, the CPUC held its deliberation meeting. Although no
revenue requirement was provided, the CPUC decisions were generally
consistent with the ALJ’s recommendation. Key matters are as follows:

• 2014 HTY, with a 13-month average rate base, with the exception of the
  Cherokee pipeline which is included at a year-end level;
• Extension of the PSIA rider through 2018 with all O&M expenses
  transferred to base rates;
• A ROE of 9.5 percent; and
• An equity ratio of 56.51 percent.

A written order is anticipated later in the first quarter.

SPS – Texas 2015 Electric Rate Case — In December 2014,
SPS filed a retail electric rate case in Texas seeking an overall
increase in annual revenue of approximately $64.8 million, or 6.7
percent. The filing was based on a HTY ending June 2014, adjusted for
known and measurable changes, a ROE of 10.25 percent, an electric rate
base of approximately $1.6 billion and an equity ratio of 53.97 percent.

SPS requested a waiver of the PUCT post-test year adjustment rule which
would allow for inclusion of $392 million (SPS total company) additional
capital investment for the period July 1, 2014 through Dec. 31, 2014. In
June 2015, SPS revised its requested rate increase to $42.1 million.

In December 2015, the PUCT made the following decisions:

• Disallowed SPS’ proposed adjustment to jurisdictional allocation
  factors to reflect Golden Spread Electric Cooperative, Inc.'s
  wholesale load reductions from 500 MW to 300 MW, effective June 1,
  2015;
• Disallowed incentive compensation;
• Approved an equity ratio of 51.00 percent instead of the actual 53.97
  percent; and
• A ROE of 9.70 percent.

The following table reflects the ALJs’ position and PUCT’s decision.

(Millions of Dollars)			ALJs’ Proposal for Decision					PUCT Decision
SPS’ revised rate request			$	42.1				$	42.1
Investment for capital expenditures — post-test year adjustments				(8.9	)				(8.9	)
Lower ROE				(6.3	)				(6.3	)
Lower capital structure				—					(3.7	)
Annual incentive compensation				(0.2	)				(0.3	)
O&M expense adjustments				(4.6	)				(4.6	)
Depreciation expense				(2.7	)				(2.7	)
Property taxes				(0.9	)				(0.9	)
Revenue adjustments				(1.1	)				(1.6	)
Wholesale load reductions				—					(11.5	)
SPP transmission expansion plan				(4.2	)				(4.2	)
Other, net				1.4					(1.2	)
Total, gross of rate case expenses			$	14.6				$	(3.8	)
Adjustment to move rate case expenses to a separate docket				(0.2	)				(0.2	)
Total, net of rate case expenses			$	14.4				$	(4.0	)
New depreciation rates				(11.2	)				(11.2	)
Earnings impact			$	3.2				$	(15.2	)

On Jan. 7, 2016, SPS filed its motion for rehearing on capital
structure, incentive compensation and known and measurable adjustments,
including wholesale load reductions and post test-year capital
additions. The PUCT has 45 days to respond to the request for rehearing.

In addition, SPS expects to file a new rate case in the first quarter of
2016 which will incorporate provisions of the legislation passed in 2015.

SPS – New Mexico 2015 Electric Rate Case — In October
2015, SPS filed a New Mexico electric rate case with the New Mexico
Public Regulation Commission (NMPRC) for a net increase in base rates of
approximately $24.3 million. The proposed net amount reflects an
increase in non-fuel base rates of $45.4 million and a decrease in base
fuel revenue of approximately $21.1 million. The decrease in base fuel
revenue will be reflected in adjustments collected through the fuel and
purchased power adjustment clause. The rate filing is based on a June
30, 2015 HTY adjusted for known and measurable changes, a requested ROE
of 10.25 percent, an electric jurisdictional rate base of approximately
$734 million and an equity ratio of 53.97 percent.

The major components of the requested rate increase are summarized below:

(Millions of Dollars)			Request
2015 base period deficiency			$	19.7
Capital expenditures — post-test year adjustments				12.3
Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage				3.7
Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects				2.0
ROE, reflecting an increase from 9.96 percent to 10.25 percent				1.6
Rider revenue adjustments - gross receipts tax				1.3
Other, net				4.8
Requested rate increase			$	45.4

The next steps in the procedural schedule are expected to be as follows:

• Settlement conference — Feb. 18-19, 2016;
• Staff and intervenor direct testimony — April 1, 2016;
• Rebuttal testimony — April 18, 2016; and
• Evidentiary hearing — April 28, 2016.

A NMPRC decision and implementation of final rates is anticipated in the
second half of 2016.

In response to the original 2015 electric rate case previously
dismissed, SPS has appealed that decision to the New Mexico Supreme
Court. A date has not yet been set for oral arguments. SPS anticipates a
decision by the first quarter of 2017.

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

Xcel Energy Earnings Guidance — Xcel Energy’s 2016 ongoing
earnings guidance is $2.12 to $2.27 per share. Key assumptions related
to 2016 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 approximately 0.5 percent to 1.0 percent.
• Weather normalized retail firm natural gas sales are projected to be
  relatively flat.
• Capital rider revenue is projected to increase by $70 million to $80
  million over 2015 levels.
• The change in O&M expenses is projected to be within a range of 0
  percent to 2 percent from 2015 levels.
• Depreciation expense is projected to increase approximately $200
  million over 2015 levels.
• Property taxes are projected to increase approximately $40 million to
  $50 million over 2015 levels.
• Interest expense (net of AFUDC — debt) is projected to increase $40
  million to $50 million over 2015 levels.
• AFUDC — equity is projected to decline approximately $10 million to
  $15 million from 2015 levels.
• The ETR is projected to be approximately 34 percent to 36 percent.
• Average common stock and equivalents are projected to be approximately
  509 million shares.

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, based
  on ongoing 2015 EPS of $2.10, which was the mid-point of Xcel Energy's
  2015 ongoing guidance range;
• 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)			2015				2014				2015					2014
Ongoing earnings			$	209,025			$	196,339			$	1,063,635				$	1,021,306
Loss on Monticello LCM/EPU project				—				—				(79,150	)				—
GAAP earnings			$	209,025			$	196,339			$	984,485				$	1,021,306

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
			2015					2014
Operating revenues:
Electric and natural gas			$	2,626,118				$	2,907,465
Other				19,703					21,163
Total operating revenues				2,645,821					2,928,628
Net income			$	209,025				$	196,339
Weighted average diluted common shares outstanding				508,738					506,799
Components of EPS — Diluted
Regulated utility			$	0.44				$	0.42
Xcel Energy Inc. and other costs				(0.03	)				(0.03	)
Ongoing diluted EPS				0.41					0.39
Loss on Monticello LCM/EPU project (a)				—					—
GAAP diluted EPS			$	0.41				$	0.39
			Twelve Months Ended Dec. 31
			2015					2014
Operating revenues:
Electric and natural gas			$	10,948,067				$	11,608,628
Other				76,419					77,507
Total operating revenues				11,024,486					11,686,135
Net income			$	984,485				$	1,021,306
Weighted average diluted common shares outstanding				508,168					504,117
Components of EPS — Diluted
Regulated utility			$	2.21				$	2.14
Xcel Energy Inc. and other costs				(0.11	)				(0.11	)
Ongoing diluted EPS (b)				2.09					2.03
Loss on Monticello LCM/EPU project (a)				(0.16	)				—
GAAP diluted EPS			$	1.94				$	2.03
Book value per share			$	20.89				$	20.20
(a) See Note 6.
(b) Amounts may not add due to rounding.

View source version on businesswire.com: http://www.businesswire.com/news/home/20160128005259/en/

Source: Business Wire
(January 28, 2016 - 6:00 AM EST)

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