Exhibit 99.01

	414 Nicollet Mall
	Minneapolis, MN 55401
Feb. 2, 2012

XCEL ENERGY

2011 YEAR END EARNINGS REPORT

● Ongoing earnings per share were $1.72 in 2011 compared with $1.62 in 2010, achieving the upper half of Xcel Energy’s guidance range.

● GAAP (generally accepted accounting principles) 2011 earnings were $841 million, or $1.72 per share, compared with $756 million, or $1.62 per share in 2010.

● Xcel Energy expects 2012 ongoing earnings will be in the lower half of the guidance range of $1.75 to $1.85 per share.

MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) today reported 2011 GAAP earnings of $841 million, or $1.72 per share compared with 2010 GAAP earnings of $756 million, or $1.62 per share.

Ongoing earnings for 2011, which exclude adjustments for certain items, were $1.72 per share compared with $1.62 per share in 2010.  Ongoing earnings increased primarily due to higher electric margins as a result of warmer than normal summer weather across our service territories and rate increases in various states.   The higher margins were partially offset by expected increases in operating and maintenance expenses, depreciation, interest expense and property taxes.  The increase in expenses was largely driven by capital investment in Xcel Energy’s utility business.

“We had an excellent year in 2011,” said Ben Fowke, Chairman, President and Chief Executive Officer.  “We delivered earnings in the upper half of our guidance range, which represents the seventh consecutive year in which we have met or exceeded our earnings guidance.  We exceeded our energy efficiency and conservation program targets.  In addition, we provided excellent customer service and reliability despite severe weather across our service territory during the latter half of the year.  Finally, the recent decision by the D.C. Circuit to stay the Cross-State Air Pollution Rule will provide us more time to comply with the rule in a cost-effective manner in Texas, preventing our customers from being burdened by significant cost increases and avoid potential reliability concerns.”

 “While it is early in the year, we are facing headwinds in 2012.  The decision by the Colorado Public Utilities Commission (CPUC) to deny our request for interim rates will increase regulatory lag in Colorado, although the impact will be partially offset by the CPUC’s approval of deferred accounting for a portion of our interim rate request.  In addition, we are experiencing sluggish electric and natural gas sales, warmer than normal winter weather and higher than anticipated property taxes.  However, we are committed to achieving our earnings guidance range and we have implemented cost reductions to help offset the impact of these negative factors.  As a result, we expect 2012 earnings per share to be in the lower half of our $1.75 to $1.85 guidance range,” stated Fowke.

Earnings Adjusted for Certain Items (Ongoing Earnings)

The following table provides a reconciliation of ongoing earnings per share to GAAP earnings per share:

	Three Months Ended Dec. 31,				Twelve Months Ended Dec. 31,
Diluted Earnings (Loss) Per Share	2011		2010		2011		2010
Ongoing(a) diluted earnings per share	$	0.29	$	0.29	$	1.72	$	1.62
COLI settlement and Medicare Part D (a)		-		-		-		(0.01	)
Earnings per share from continuing operations		0.29		0.29		1.72		1.61
Earnings per share from discontinued operations		-		-		-		0.01
GAAPdiluted earnings per share	$	0.29	$	0.29	$	1.72	$	1.62

(a) See Note 6.

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At 10 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:	(877) 941-8609
International Dial-In:	(480) 629-9818
Conference ID:	4502443

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 Information.  If you are unable to participate in the live event, the call will be available for replay from 2:00 p.m. CST on Feb. 2 through 11:59 p.m. CST on Feb. 3.

Replay Numbers
US Dial-In:	(800) 406-7325
International Dial-In:	(303) 590-3030
Access Code:	4502443#

Except for the historical statements contained in this release, the matters discussed herein, including our 2012 full year earnings per share guidance and assumptions, are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements 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 do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: 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 Inc. and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; 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 imposed 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; actions by regulatory bodies impacting our nuclear operations, including those affecting costs, operations or the approval of requests pending before the Nuclear Regulatory Commission; financial or regulatory accounting policies imposed by regulatory bodies; availability of cost of capital; employee work force factors; and the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Risk Factors in Item 1A and Exhibit 99.01 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2010 and Quarterly Reports on Form 10-Q for the quarters ended March 31, June 30 and Sept. 30, 2011.

For more information, contact:

Paul Johnson, Vice President, Investor Relations and Financial Management	(612) 215-4535
Jack Nielsen, Director, Investor Relations	(612) 215-4559
Cindy Hoffman, Senior Investor Relations Analyst	(612) 215-4536
For news media inquiries only, please call Xcel Energy media relations	(612) 215-5300
Xcel Energy internet address: www.xcelenergy.com

This information is not given in connection with any

sale, offer for sale or offer to buy any security.

2

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,
	2011			2010			2011			2010
Operating revenues
Electric	$	1,988,800		$	1,974,634		$	8,766,593		$	8,451,845
Natural gas		560,109			572,428			1,811,926			1,782,582
Other		19,501			19,872			76,251			76,520
Total operating revenues		2,568,410			2,566,934			10,654,770			10,310,947
Operating expenses
Electric fuel and purchased power		920,293			925,313			3,991,786			4,010,660
Cost of natural gas sold and transported		370,351			388,279			1,163,890			1,162,926
Cost of sales — other		8,291			8,296			30,391			29,540
Operating and maintenance expenses		565,130			550,002			2,140,289			2,057,249
Conservation and demand side management program expenses		69,303			65,376			281,378			239,827
Depreciation and amortization		194,303			219,579			890,619			858,882
Taxes (other than income taxes)		96,738			87,719			374,815			331,894
Total operating expenses		2,224,409			2,244,564			8,873,168			8,690,978
Operating income		344,001			322,370			1,781,602			1,619,969
Other income, net		960			1,009			9,255			31,143
Equity earnings of unconsolidated subsidiaries		7,714			7,515			30,527			29,948
Allowance for funds used during construction — equity		12,533			16,402			51,223			56,152
Interest charges and financing costs
Interest charges — includes other financing costs of $6,295, $5,252, $24,019 and $20,638, respectively		152,395			147,158			591,098			577,291
Allowance for funds used during construction — debt		(6,606	)		(8,035	)		(28,181	)		(28,670	)
Total interest charges and financing costs		145,789			139,123			562,917			548,621
Income from continuing operations before income taxes		219,419			208,173			1,309,690			1,188,591
Income taxes		78,478			71,671			468,316			436,635
Income from continuing operations		140,941			136,502			841,374			751,956
Income (loss) from discontinued operations, net of tax		(432	)		131			(202	)		3,878
Net income		140,509			136,633			841,172			755,834
Dividend requirements on preferred stock		-			1,060			3,534			4,241
Premium on redemption of preferred stock		-			-			3,260			-
Earnings available to common shareholders	$	140,509		$	135,573		$	834,378		$	751,593
Weighted average common shares outstanding:
Basic		486,223			468,686			485,039			462,052
Diluted		486,991			471,325			485,615			463,391
Earnings per average common share — basic:
Income from continuing operations	$	0.29		$	0.29		$	1.72		$	1.62
Income from discontinued operations		-			-			-			0.01
Earnings per share	$	0.29		$	0.29		$	1.72		$	1.63
Earnings per average common share — diluted:
Income from continuing operations	$	0.29		$	0.29		$	1.72		$	1.61
Income from discontinued operations		-			-			-			0.01
Earnings per share	$	0.29		$	0.29		$	1.72		$	1.62
Cash dividends declared per common share	$	0.26		$	0.25		$	1.03		$	1.00

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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 earnings and earnings per share (EPS) 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.  EPS by subsidiary is a financial measure not recognized under GAAP that is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.  We use this non-GAAP financial measure to evaluate and provide details of earnings results.  We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries.  This non-GAAP financial measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.

Note 1.  Earnings Per Share Summary

The following table summarizes the diluted earnings per share for Xcel Energy:

	Three Months Ended Dec. 31,						Twelve Months Ended Dec. 31,
Diluted Earnings (Loss) Per Share	2011			2010			2011			2010
Public Service Company of Colorado (PSCo)	$	0.18		$	0.17		$	0.82		$	0.86
NSP-Minnesota		0.11			0.12			0.73			0.60
Southwestern Public Service Company (SPS)		0.01			0.01			0.18			0.17
NSP-Wisconsin		0.02			0.02			0.10			0.09
Equity earnings of unconsolidated subsidiaries		0.01			0.01			0.04			0.04
Regulated utility — continuing operations (a)		0.33			0.33			1.87			1.76
Xcel Energy Inc. and other costs		(0.04	)		(0.04	)		(0.15	)		(0.14	)
Ongoing(b) diluted earnings per share		0.29			0.29			1.72			1.62
COLI settlement and Medicare Part D (b)		-			-			-			(0.01	)
Earnings per share from continuing operations		0.29			0.29			1.72			1.61
Earnings per share from discontinued operations		-			-			-			0.01
GAAPdiluted earnings per share	$	0.29		$	0.29		$	1.72		$	1.62

(a) See Note 2.

(b) See Note 6.

PSCo — PSCo earnings decreased $0.04 per share for 2011. The decrease is due to the implementation of seasonal rates in June 2010 (seasonal rates are higher in the summer months and lower throughout the other months of the year), higher operating and maintenance (O&M) expenses, depreciation expense and property taxes, partially offset by the favorable impact of warmer temperatures in the summer.

NSP-Minnesota — NSP-Minnesota earnings increased $0.13 per share for 2011.   The increase is primarily due to higher interim electric rates effective in early 2011, subject to refund, in Minnesota and North Dakota, and conservation program incentives partially offset by higher O&M expenses, depreciation expense (net of regulatory adjustments) and property taxes.

SPS — SPS earnings increased $0.01 per share for 2011.  The increase is due to higher electric revenues, primarily due to the Texas retail rate increase effective in the first quarter of 2011, and warmer summer weather, partially offset by higher O&M expenses, depreciation expense and property taxes.

NSP-Wisconsin — NSP-Wisconsin earnings increased $0.01 per share for 2011.   The increase is primarily due to higher electric rates, partially offset by higher O&M expenses and depreciation expense.

4

The following table summarizes significant components contributing to the changes in the 2011 diluted EPS compared with the same periods in 2010, which is discussed in more detail later in the release.

Diluted Earnings (Loss) Per Share	Three Months  Ended Dec. 31,			Twelve Months Ended Dec. 31,
2010 GAAP diluted earnings per share	$	0.29		$	1.62
Earnings per share from discontinued operations		-			(0.01	)
2010 diluted earnings per share from continuing operations		0.29			1.61
COLI settlement and Medicare Part D (a)		-			0.01
2010 ongoing(a) diluted earnings per share		0.29			1.62
Components of change — 2011 vs. 2010
Higher electric margins		0.03			0.44
Higher natural gas margins		0.01			0.04
Higher operating and maintenance expenses		(0.02	)		(0.11	)
Dilution from DSPP, benefit plans and the 2010 common equity issuance		(0.01	)		(0.08	)
Higher taxes (other than income taxes)		(0.01	)		(0.06	)
Higher conservation and DSM expenses (generally offset in revenues)		(0.01	)		(0.05	)
Lower (higher) depreciation and amortization		0.03			(0.04	)
Other, net (including interest and premium on redemption of preferred stock)		(0.02	)		(0.04	)
2011 GAAP and ongoing(a) diluted earnings per share	$	0.29		$	1.72

(a) See Note 6.

Note 2.  Regulated Utility Results — Continuing Operations

Estimated Impact of Temperature Changes on Regulated Earnings — Unseasonably hot summers or cold winters increase electric and natural gas sales while, conversely, 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, and 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 weather sensitive.

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 the time period used by the regulator in establishing estimated volumes in the rate setting process.

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

	Three Months Ended Dec. 31,												Twelve Months Ended Dec. 31,
	2011 vs. Normal				2010 vs. Normal (a)				2011 vs. 2010 (a)				2011 vs. Normal			2010 vs. Normal (a)			2011 vs. 2010 (a)
HDD		(8.7	)	%		(5.9	)	%		(3.0	)	%		(1.0	) %		(4.3	) %		3.5	%
CDD		N/A		(b)		N/A		(b)		N/A		(b)		38.1			11.9			23.4
THI		N/A		(b)		N/A		(b)		N/A		(b)		37.9			29.9			6.1

(a) Adjusted for the October 2010 sale of SPS electric distribution assets to the city of Lubbock, Texas.

(b) CDD’s and THI’s have no meaningful impact on fourth quarter sales.

5

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

	Three Months Ended Dec. 31,								Twelve Months Ended Dec. 31,
	2011 vs. Normal			2010 vs. Normal			2011 vs. 2010		2011 vs. Normal		2010 vs. Normal			2011 vs. 2010
Retail electric	$	(0.01	)	$	(0.01	)	$	0.00	$	0.07	$	0.04		$	0.03
Firm natural gas		0.00			0.00			0.00		0.00		(0.01	)		0.01
Total	$	(0.01	)	$	(0.01	)	$	0.00	$	0.07	$	0.03		$	0.04

Sales Growth (Decline)— The following table summarizes Xcel Energy’s sales growth (decline) for actual and weather-normalized sales in 2011:

	Three Months Ended Dec. 31,
	Actual			Weather Normalized			Actual Lubbock (a)			Weather Normalized Lubbock (a)
Electric residential		(0.3	) %		(0.4	) %		(0.1	) %		(0.1	) %
Electric commercial and industrial		(0.3	)		(0.5	)		0.0			(0.2	)
Total retail electric sales		(0.3	)		(0.4	)		0.0			(0.1	)
Firm natural gas sales		0.4			(1.6	)		N/A			N/A

	Twelve Months Ended Dec. 31,
	Actual			Weather Normalized			Actual Lubbock (a)			Weather Normalized Lubbock (a)
Electric residential		0.5	%		(0.5	) %		1.3	%		0.2	%
Electric commercial and industrial		0.3			0.0			1.1			0.7
Total retail electric sales		0.4			(0.1	)		1.2			0.6
Firm natural gas sales		0.9			(2.5	)		N/A			N/A

(a)Adjusted for the October 2010 sale of SPS electric distribution assets to the city of Lubbock, Texas.

Electric— 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 little 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)			2011			2010				2011			2010
Electric revenues		$	1,989		$	1,975			$	8,767		$	8,452
Electric fuel and purchased power			(920	)		(925	)			(3,992	)		(4,011	)
Electric margin		$	1,069		$	1,050			$	4,775		$	4,441

6

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

	Three Months  Ended Dec. 31, 2011 vs. 2010			Twelve Months  Ended Dec. 31, 2011 vs. 2010
(Millions of Dollars)
Revenue requirements for PSCo gas generation acquisition (a)	$	26		$	124
Retail rate increases (net of revenue subject to refund)(b)		4			102
Conservation and DSM revenue (offset by expenses)		4			31
Transmission revenue, net of costs		5			20
Estimated impact of weather		(2	)		18
Conservation and DSM incentive		(2	)		14
Non-fuel riders		(13	)		(5	)
Other, net (including firm wholesale and deferred fuel adjustments)		(3	)		30
Total increase in electric margin	$	19		$	334

(a) The increase in revenue requirements for PSCo generation reflects the acquisition of the Rocky Mountain and Blue Spruce natural gas facilities in late 2010.  These revenue requirements are partially offset by higher O&M expense, depreciation expense, property taxes and financing costs.

(b) The retail rate increases include final rates in Wisconsin and Texas and interim rates, subject to refund, in Minnesota and North Dakota.  The rate increases are net of a provision for refund of approximately $67 million for Minnesota and $2.3 million for North Dakota, based on settlements reached with various parties in both cases.  In addition, NSP-Minnesota reduced depreciation expense and revenues by approximately $30 million in the fourth quarter of 2011 to reflect the proposed settlement in the Minnesota electric rate case.  These settlements are pending commission decisions in both Minnesota and North Dakota.

Natural Gas — The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases.  However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect 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)			2011			2010				2011			2010
Natural gas revenues		$	560		$	572			$	1,812		$	1,783
Cost of natural gas sold and transported			(370	)		(388	)			(1,164	)		(1,163	)
Natural gas margin		$	190		$	184			$	648		$	620

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

(Millions of Dollars)	Three Months Ended Dec. 31,  2011 vs. 2010			Twelve Months  Ended Dec. 31, 2011 vs. 2010
Conservation and DSM revenue (offset by expenses)	$	1		$	13
Estimated impact of weather		-			9
Return on PSCo gas in storage		4			4
Retail rate increase (Colorado)		3			3
Retail sales decrease (excluding weather impact)		(1	)		(5	)
Conservation and DSM incentive		(3	)		(2	)
Other, net		2			6
Total increase in natural gas margin	$	6		$	28

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O&M Expenses — O&M expenses increased $15.1 million, or 2.8 percent, for the fourth quarter and $83.0 million, or 4.0 percent for 2011 compared with 2010.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	Three Months Ended Dec. 31, 2011 vs. 2010			Twelve Months  Ended Dec. 31,  2011 vs. 2010
(Lower) higher plant generation costs	$	(2	)	$	22
Higher labor and contract labor costs		1			18
Higher employee benefit expense		4			13
Higher nuclear plant operation costs		9			12
Higher insurance costs		3			4
Other, net		-			14
Total increase in O&M expenses	$	15		$	83

● Higher plant generation costs are attributable to incremental costs associated with new generation placed in service and a higher level of scheduled maintenance and overhaul work.

● Higher labor and contract labor costs are primarily due to maintenance on our distribution facilities and the impact of annual wage increases.

● Higher employee benefit costs are largely driven by higher pension expense.

● Higher nuclear plant operation costs were largely driven by outages.

Conservation and DSM Program Expenses — Conservation and demand side management (DSM) program expenses increased $3.9 million, or 6.0 percent for the fourth quarter and $41.6 million, or 17.3 percent for 2011, compared with 2010.  The higher expense is primarily attributable to an increase in the rider rates used to recover the program expenses.  Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense decreased $25.3 million, or 11.5 percent for the fourth quarter. This decrease is primarily due to NSP-Minnesota reducing depreciation expense by approximately $30 million in the fourth quarter of 2011 to reflect the proposed settlement in the Minnesota electric rate case.  This was partially offset by several capital projects, including a portion of the Monticello extended power uprate going into service in May 2011, the Nobles wind project commencing commercial operations in late 2010, the acquisition of two PSCo gas generation facilities in December 2010, Jones Unit 3 going into service in June 2011 and normal system expansion.

Depreciation and amortization expense increased $31.7 million, or 3.7 percent for 2011, compared with 2010.  This increase in depreciation expense is primarily due to several capital projects going into service, including those discussed above, partially offset by the provision for revenue, subject to refund.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $9.0 million, or 10.3 percent for the fourth quarter and $42.9 million, or 12.9 percent for 2011, compared with 2010.  The change is primarily due to an increase in 2011 for property taxes of approximately $29.6 million in Colorado and $8.8 million in Minnesota.

Other Income, Net — Other income, net decreased $21.9 million for 2011, compared with 2010, primarily due to the corporate owned life insurance (COLI) settlement in July 2010.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased $5.3 million, or 21.7 percent for the fourth quarter and $5.4 million, or 6.4 percent for 2011, compared with 2010.  The decrease is primarily due to lower AFUDC rates and lower average construction work in progress.  The lower average construction work in progress is attributed to Comanche Unit 3 and the Nobles wind project going into service in 2010, offset by Monticello extended power uprate and work at the Jones plant, as well as SPS transmission projects in 2011.

Interest Charges — Interest charges increased $5.2 million, or 3.6 percent for the fourth quarter and $13.8 million, or 2.4 percent for 2011, compared with 2010.  The increase is due to higher long-term debt levels necessary to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense for continuing operations increased $6.8 million for the fourth quarter of 2011, compared with the same period in 2010.  The increase in income tax expense was primarily due to an increase in pretax income in 2011.  The effective tax rate for continuing operations was 35.8 percent for the fourth quarter of 2011 compared with 34.4 percent for the same period in 2010.  The lower effective tax rate for 2010 was primarily due to a higher level of research credits.

8

Income tax expense for continuing operations increased $31.7 million for 2011 compared with 2010.  The increase is primarily due to higher pretax income, a net change in tax valuation allowances of $8.9 million, and the non-taxability of the Provident settlement in 2010.  These were partially offset by the 2010 write-off of the tax benefit for Medicare Part D subsidies, an adjustment related to COLI (see Note 6), and an increase in 2011 wind production tax credits.  The effective tax rate for continuing operations was 35.8 percent for 2011 compared with 36.7 percent for 2010.  The higher effective tax rate for 2010 was primarily due to the Medicare Part D, COLI, and the valuation allowance adjustments referenced above.  Without these adjustments, the effective tax rate for continuing operations for 2010 would have been 35.1 percent.

Premium on Redemption of Preferred Stock —Xcel Energy Inc. redeemed all series of its preferred stock on Oct. 31, 2011, at an aggregate purchase price of $108 million, plus accrued dividends.  As such, the redemption premium of $3.3 million and accrued dividends are reflected as reductions to earnings available to common shareholders for 2011.

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

Following is the capital structure of Xcel Energy:

(Billions of Dollars)	Dec. 31, 2011		Percentage of Total Capitalization
Current portion of long-term debt	$	1.1		6	%
Short-term debt		0.2		1
Long-term debt		8.8		47
Total debt		10.1		54
Common equity		8.5		46
Total capitalization	$	18.6		100	%

Financing Plans — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund construction programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes.

During 2011, Xcel Energy Inc. and its utility subsidiaries completed the following financings:

● In August 2011, PSCo issued $250 million of 30-year first mortgage bonds with a coupon of 4.75 percent.

● In August 2011, SPS issued $200 million of 30-year first mortgage bonds with a coupon of 4.5 percent.

● In September 2011, Xcel Energy Inc. issued $250 million of 30-year unsecured bonds with a coupon of 4.8 percent.

● In October 2011, Xcel Energy Inc. redeemed all series of its preferred stock, which had a par value of $105 million.

During 2012, Xcel Energy Inc. and its utility subsidiaries anticipate issuing following:

● NSP-Minnesota may issue approximately $800 million of first mortgage bonds in the third quarter of 2012.

● PSCo may issue approximately $750 million of first mortgage bonds in the third quarter of 2012.

● SPS may issue approximately $100 million of first mortgage bonds in the first half of 2012.

● NSP-Wisconsin may issue approximately $100 million of first mortgage bonds in the second half of 2012.

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

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Credit Facilities —As of  Jan. 25, 2012, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:

(Millions of Dollars)	Facility		Drawn(a)		Available		Cash		Liquidity		Maturity
Xcel Energy Inc.	$	800.0	$	184.1	$	615.9	$	0.3	$	616.2	March 2015
PSCo		700.0		72.9		627.1		0.2		627.3	March 2015
NSP-Minnesota		500.0		79.7		420.3		0.9		421.2	March 2015
SPS		300.0		50.0		250.0		0.4		250.4	March 2015
NSP-Wisconsin		150.0		89.0		61.0		0.4		61.4	March 2015
Total	$	2,450.0	$	475.7	$	1,974.3	$	2.2	$	1,976.5

 (a) Includes outstanding commercial paper and letters of credit.

Credit Ratings — Access to reasonably priced capital markets is dependent in part on credit and 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, 2012, 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	Baa1	BBB+	BBB+
Xcel Energy Inc.	Commercial Paper	P-2	A-2	F2
NSP-Minnesota	Senior Unsecured Debt	A3	A-	A
NSP-Minnesota	Senior Secured Debt	A1	A	A+
NSP-Minnesota	Commercial Paper	P-2	A-2	F1
NSP-Wisconsin	Senior Unsecured Debt	A3	A-	A
NSP-Wisconsin	Senior Secured Debt	A1	A	A+
NSP-Wisconsin	Commercial Paper	P-2	A-2	F1
PSCo	Senior Unsecured Debt	Baa1	A-	A-
PSCo	Senior Secured Debt	A2	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 ratings 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.

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Capital Expenditures — The estimated capital expenditure programs of Xcel Energy Inc. and its subsidiaries for the years 2012 through 2016 are shown in the tables below.

(Millions of Dollars)	2012		2013		2014		2015		2016
By Subsidiary
NSP-Minnesota	$	1,130	$	1,390	$	1,150	$	1,040	$	1,200
PSCo		900		1,020		920		730		720
SPS		460		730		430		320		340
NSP-Wisconsin		160		160		200		210		190
Total capital expenditures	$	2,650	$	3,300	$	2,700	$	2,300	$	2,450

By Function	2012		2013		2014		2015		2016
Electric transmission	$	710	$	945	$	740	$	660	$	710
Electric generation		570		680		495		450		345
Electric distribution		445		400		420		460		465
Environmental		300		690		410		190		270
Natural gas		245		275		275		225		245
Nuclear fuel		145		95		160		105		245
Other		235		215		200		210		170
Total capital expenditures	$	2,650	$	3,300	$	2,700	$	2,300	$	2,450

By Project	2012		2013		2014		2015		2016
Base and other capital expenditures	$	1,850	$	1,815	$	1,690	$	1,670	$	2,030
PSCo Clean Air-Clean Jobs Act		200		410		260		95		10
CapX2020		175		350		285		145		-
Nuclear fuel		145		95		160		105		245
Nuclear capacity increases and life extension		145		295		105		95		-
Cross-State Air Pollution Rule (CSAPR) (a)		75		255		115		25		-
RES and infrastructure investments		60		80		85		165		165
Total capital expenditures	$	2,650	$	3,300	$	2,700	$	2,300	$	2,450

(a) In July 2011, the EPA issued its CSAPR, to address long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide and nitrogen oxide from utilities located in the eastern half of the U.S.  On Dec. 30, 2011, the D.C. Circuit issued a stay of the CSAPR, pending completion of judicial review of the rule.  Xcel Energy is in the process of determining various scenarios to respond to the CSAPR depending on whether the CSAPR is upheld, reversed, or modified.  The expected cost for these various scenarios cannot be determined at this time and may impact the amount of estimated capital expenditures disclosed above.

The capital expenditure programs of Xcel Energy are subject to continuing review and modification.  Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions, legislative initiatives, reserve margins, the availability of purchased power, alternative plans for meeting long-term energy needs, compliance with future environmental requirements and renewable portfolio standards to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

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Note 4.  Rates and Regulation

NSP-Minnesota – Minnesota Electric Rate Case— In November 2010, NSP-Minnesota filed a request with the Minnesota Public Utilities Commission (MPUC) to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million, or 1.81 percent in 2012.  The rate filing was based on a 2011 forecast test year and included a requested return on equity (ROE) of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent.  The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011.

In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments.  The Division of Energy Resources (DOER) revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent.  The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation were associated with ROE and compensation related issues.

In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million.  The revisions were due to delays in the Monticello nuclear plant extended power uprate.

In November 2011, NSP-Minnesota reached a settlement agreement with the Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group and Verso Paper Corp., which settled all financial issues and several rate design issues between the signing parties.  The settlement includes a rate increase of approximately $58.0 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent. The settlement agreement reflects a reduction to depreciation expense and NSP-Minnesota’s rate request by $30 million with an additional adjustment of $7.5 million related to employee compensation.  The settlement also provided NSP-Minnesota the ability to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012, which is currently projected to increase by approximately $28 million.  NSP-Minnesota also agreed to not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement and the property tax filing are approved by the MPUC. NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $67.4 million for 2011.  The MPUC is expected to rule on the settlement in the first quarter of 2012.

NSP-Minnesota – North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent in 2011 and a step increase of $4.2 million, or 2.6 percent in 2012.  The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.

The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011.  The interim rates will remain in effect until the NDPSC makes its final decision on the case.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012, due to the termination of the Merricourt wind project.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff.  If approved by the NDPSC, the settlement would result in a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues.  To address 2011 sales coming in below test year projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.

An NDPSC decision is expected in March 2012.

NSP-Minnesota – South Dakota Electric Rate Case—In June 2011, NSP-Minnesota filed a request with the South Dakota Public Utility Commission (SDPUC) to increase South Dakota electric rates by $14.6 million annually, effective in 2012.  The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms.  The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year.

As a result of delays in the rate case process, interim rates of $12.7 million were implemented Jan. 2, 2012.  A final decision is expected in the first half of 2012.

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NSP-Wisconsin 2011 Electric and Gas Rate Case — In June 2011, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) to increase electric rates approximately $29.2 million, or 5.1 percent and natural gas rates approximately $8.0 million, or 6.6 percent effective Jan. 1, 2012.  The rate filing is based on a 2012 forecast test year and includes a requested ROE of 10.75 percent, an equity ratio of 52.54 percent, an electric rate base of approximately $718 million and a natural gas rate base of $84 million.

In December 2011, the PSCW approved an electric rate increase of approximately $12.2 million or 2.1 percent, and a natural gas rate increase of $2.9 million or 2.4 percent, with new rates effective Jan. 1, 2012.  The primary reason for the natural gas rate reduction from the original request was the PSCW decision to deny NSP-Wisconsin’s proposal to pre-collect certain manufactured gas plant remediation costs.  The primary reasons for the electric rate reduction were updated 2012 electric fuel costs and the delays in the Monticello nuclear plant life cycle management and extended power uprate project.  The rate increases were based on a 10.4 percent ROE and an equity ratio of 52.59 percent.

SPS – New Mexico Retail Rate Case — In February 2011, SPS filed a request with the New Mexico Public Regulation Commission (NMPRC) seeking to increase New Mexico electric rates approximately $19.9 million.  The rate filing was based on a 2011 test year adjusted for known and measurable changes for 2012, a requested ROE of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent.

In December 2011, the NMPRC approved the black box settlement with new rates effective Jan. 1, 2012.  The settlement increased base rates by $13.5 million.  SPS agreed not to file another base rate case until Dec. 3, 2012 with new final rates from the result of such case not going into effect until Jan. 1, 2014 (Settlement Period).  However, SPS can request to implement interim rates if the NMPRC standard for interim rates is met.  During the Settlement Period, rates are to remain fixed aside from the continued operation of the fuel adjustment clause and certain exceptions for energy efficiency, a rider for an approved renewable portfolio standard regulatory asset, and actual costs incurred for environmental regulations with an effective date after Dec. 31, 2010.

PSCo Wholesale Electric Rate Case — In February 2011, PSCo filed with the Federal Energy Regulatory Commission to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011.  The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent.  The formula rate would be estimated each year for the following year and then trued-up to actual costs after the conclusion of the calendar year.  A decision is expected in the first quarter of 2012.

PSCo 2010 Gas Rate Case — In December 2010, PSCo filed a request with the CPUC to increase Colorado retail gas rates by $27.5 million on an annual basis.  In March 2011, PSCo revised its requested rate increase to $25.6 million. The revised request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.1 percent.  PSCo proposed recovering $23.2 million of test year capital and O&M expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006.  PSCo also proposed removing the earnings on gas in underground storage from base rates.

In August 2011, the CPUC approved a comprehensive settlement that PSCo reached with the CPUC Staff and the Colorado Office of Consumer Counsel (OCC) to increase rates by $12.8 million, to institute the pipeline system integrity adjustment (PSIA) rider for recovery of future pipeline integrity costs and to remove gas in underground storage from base rates and recover those costs in the Gas Cost Adjustment (GCA).  The GCA is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs.  Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent.

New base rates and the GCA recovery went into effect in September 2011.  The PSIA rider and new rate designs went into effect on Jan. 1, 2012.

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PSCo 2011 Electric Rate Case —In November 2011, PSCo filed a request with the CPUC to increase Colorado retail electric rates by $141.9 million.  The request was based on a 2012 forecast test year, a 10.75 percent ROE, a rate base of $5.4 billion and an equity ratio of 56 percent.  Final rates are expected to be effective in the summer of 2012.The CPUC is expected to rule on the electric rate case in July 2012.

In November 2011, PSCo filed a petition to implement interim rates, subject to refund, of $100 million to be effective in January 2012.  On Jan. 11, 2012, the CPUC denied PSCo’s request to implement an interim electric rate increase of $100 million on the basis that it had not demonstrated adverse financial impacts.  On Jan. 12, 2012, PSCo filed for reconsideration of the CPUC’s decision to deny interim rates, and requested that the CPUC authorize interim rates of approximately $42 million, specifically related to the impacts resulting from the expiration of the Black Hills contract.  On Jan. 17, 2012, the CPUC denied the request for reconsideration.  However, on Jan. 27, 2012, the CPUC approved PSCo’s request for deferred accounting of the $42 million revenue requirement associated with the Black Hills contract.

Note 5.  Xcel Energy Ongoing Earnings Guidance

Xcel Energy expects its 2012 ongoing earnings will be in the lower half of the guidance range of $1.75 to $1.85 per share.  Key assumptions related to ongoing earnings are detailed below:

● Constructive outcomes in all rate case and regulatory proceedings.

● Normal weather patterns are experienced for the year.

● Weather-adjusted retail electric utility sales are projected to grow 0.5 to 1.0 percent.

● Weather-adjusted retail firm natural gas sales are projected to be relatively flat.

● Rider revenue recovery is projected to increase approximately $50 million to $60 million over 2011 levels.

● O&M expenses are projected to increase approximately 1.0 to 3.0 percent over 2011 levels.

● Depreciation expense is projected to increase $60 million to $70 million over 2011 levels.   This assumes depreciation expense in both 2011 and 2012 is reduced by $30 million, consistent with the settlement agreement in the Minnesota electric rate case, which is pending a MPUC decision.

● Property taxes are projected to increase by $20 million to $25 million over 2011 levels, net of NSP-Minnesota’s request for deferred accounting for 2012 property tax increases, which is pending a MPUC decision.

Interest expense (net of AFUDC — debt) is projected to be relatively flat.

● AFUDC — equity is projected to increase approximately $25 million to $30 million over 2011 levels.

● The effective tax rate is projected to be approximately 34 percent to 36 percent.

● Average common stock and equivalents are projected to be approximately 488 million shares.

Note 6.  Non-GAAP Reconciliation

Xcel Energy’s management believes that ongoing earnings provide a meaningful comparison of earnings results and is representative of Xcel Energy’s fundamental core earnings power.  Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for performance-based compensation, and when communicating its earnings outlook to analysts and investors.

The following table provides a reconciliation of ongoing earnings to GAAP earnings:

	Three Months Ended Dec. 31,						Twelve Months Ended Dec. 31,
(Thousands of Dollars)	2011			2010			2011			2010
Ongoingearnings	$	140,567		$	137,664		$	840,914		$	756,501
COLI settlement and Medicare Part D		374			(1,162	)		460			(4,545	)
Total continuing operations		140,941			136,502			841,374			751,956
Income (loss) from discontinued operations		(432	)		131			(202	)		3,878
GAAPearnings	$	140,509		$	136,633		$	841,172		$	755,834

Ongoing earnings exclude the impact of Internal Revenue Service (IRS) tax and interest adjustments related to the COLI program, the write-off of previously recognized tax benefits relating to Medicare Part D subsidies due to the enacted Patient Protection and Affordable Care Act and a settlement related to the previously discontinued COLI program.

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Impact of the Patient Protection and Affordable Care Act — Medicare Part D — In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.  Based on this provision, Xcel Energy is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.  Xcel Energy expensed approximately $17 million, or $0.04 per share, of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010.  Xcel Energy does not expect the $17 million of additional tax expense to recur in future periods.

COLI — During 2007, Xcel Energy Inc. and PSCo reached a settlement with the IRS related to a dispute associated with its COLI program.  These COLI policies were owned and managed by P.S.R. Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo.  As a follow on to the 2007 IRS COLI settlement, as part of the Tax Court proceedings, during the first quarter of 2010, Xcel Energy Inc., PSCo and the IRS reached an agreement in principle after a comprehensive financial reconciliation of Xcel Energy Inc.'s and PSCo’s statements of account, dating back to tax year 1993.  Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $10 million (including $7.7 million tax expense and $2.3 million interest expense, net of tax), or $0.02 per share during the first quarter of 2010.  During the third quarter of 2010, Xcel Energy Inc. and the IRS came to final agreement on the applicable interest netting computations related to these tax years.  Accordingly, PSRI recorded a reduction to expense of $0.6 million, net of tax, during the third quarter of 2010.  The Tax Court proceedings were dismissed in December 2010 and January 2011.  Upon final cash settlement in fourth quarter 2011, Xcel Energy received $0.7 million and recognized a further reduction of expense of $0.3 million (including $0.4 million tax benefit and $0.1 million interest expense, net of tax).  A closing agreement covering tax years 2003 through 2007 was finalized with the IRS in January 2012.

In July 2010, Xcel Energy Inc., PSCo and PSRI entered into a settlement agreement with Provident Life & Accident Insurance Company (Provident) related to all claims asserted by Xcel Energy Inc., PSCo and PSRI against Provident in a lawsuit associated with the discontinued COLI program.  Under the terms of the settlement, Xcel Energy Inc., PSCo and PSRI were paid $25 million by Provident and Reassure America Life Insurance Company resulting in approximately $0.05 of non-recurring earnings per share in the third quarter of 2010.  The $25 million proceeds were not subject to income taxes.

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XCEL ENERGY INC. AND SUBSIDIARIES

EARNINGS RELEASE SUMMARY (Unaudited)

(amounts in thousands, except earnings per share)

	Three Months Ended Dec. 31,
	2011			2010
Operating revenues:
Electric and natural gas revenues	$	2,548,909		$	2,547,062
Other		19,501			19,872
Total operating revenues		2,568,410			2,566,934
Income from continuing operations		140,941			136,502
Income (loss) from discontinued operations		(432	)		131
Net income	$	140,509		$	136,633
Earnings available to common shareholders	$	140,509		$	135,573
Weighted average diluted common shares outstanding		486,991			471,325
Components of Earnings per Share — Diluted
Regulated utility — continuing operations	$	0.33		$	0.33
Xcel Energy Inc. and other costs		(0.04	)		(0.04	)
Ongoing(a) diluted earnings per share		0.29			0.29
COLI settlement and Medicare Part D (a)		-			-
Earnings per share from continuing operations		0.29			0.29
Earnings per share from discontinued operations		-			-
GAAPdiluted earnings per share	$	0.29		$	0.29

	Twelve Months Ended Dec. 31,
	2011			2010
Operating revenues:
Electric and natural gas revenues	$	10,578,519		$	10,234,427
Other		76,251			76,520
Total operating revenues		10,654,770			10,310,947
Income from continuing operations		841,374			751,956
Income (loss) from discontinued operations		(202	)		3,878
Net income	$	841,172		$	755,834
Earnings available to common shareholders	$	834,378		$	751,593
Weighted average diluted common shares outstanding		485,615			463,391
Components of Earnings per Share — Diluted
Regulated utility — continuing operations	$	1.87		$	1.76
Xcel Energy Inc. and other costs		(0.15	)		(0.14	)
Ongoing(a) diluted earnings per share		1.72			1.62
COLI settlement and Medicare Part D (a)		-			(0.01	)
Earnings per share from continuing operations		1.72			1.61
Earnings per share from discontinued operations		-			0.01
GAAPdiluted earnings per share	$	1.72		$	1.62
Book value per share	$	17.44		$	16.76

(a)  See Note 6.

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