Exhibit 99.01

414 Nicollet Mall

Minneapolis, MN 55401

Aug. 2, 2012

XCEL ENERGY

SECOND QUARTER 2012 EARNINGS REPORT

· 2012 second quarter earnings per share were $0.38 compared with $0.33 per share in 2011.

· Xcel Energy expects 2012 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 2012 second quarter earnings of $183 million, or $0.38 per share compared with 2011 earnings of $159 million, or $0.33 per share.

Second quarter 2012 earnings increased largely due to higher electric margin, resulting from various rate increases and warmer than normal weather across all of Xcel Energy’s service territories.  Higher property taxes and interest expense partially offset the strong electric margins.

“I am pleased to report strong second quarter earnings,” said Ben Fowke, Chairman, President and Chief Executive Officer.  “Warmer weather combined with operating and maintenance cost management initiatives allowed us to mitigate the negative impact of regulatory decisions, including the Minnesota Commission’s denial of our request to defer incremental property taxes in 2012.”

“As a result, we continue to expect 2012 earnings per share to be in the lower half of our $1.75 to $1.85 guidance range.”

At 9:00 a.m. CDT today, Xcel Energy will host a conference call to review financial results.  To participate in the call, please dial in 5 to 10 minutes prior to the start and follow the operator’s instructions.

US Dial-In:	(800) 762-8779
International Dial-In:	(480) 629-9645
Conference ID:	4548947

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 2:00 p.m. CDT on Aug. 2 through 11:59 p.m. CDT on Aug. 3.

Replay Numbers
US Dial-In:	(800) 406-7325
International Dial-In:	(303) 590-3030
Access Code:	4548947#

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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 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; 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 or 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 Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

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.

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(amounts in thousands, except per share data)

	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011
Operating revenues
Electric	$	2,036,829		$	2,128,397		$	3,973,611		$	4,158,369
Natural gas		221,313			291,538			842,348			1,056,887
Other		16,526			18,287			36,788			39,506
Total operating revenues		2,274,668			2,438,222			4,852,747			5,254,762
Operating expenses
Electric fuel and purchased power		854,373			989,413			1,718,353			1,921,241
Cost of natural gas sold and transported		89,759			163,056			507,705			706,432
Cost of sales — other		5,944			6,891			13,248			14,946
Operating and maintenance expenses		534,014			532,170			1,044,698			1,042,197
Conservation and demand side management program expenses		58,615			65,497			122,322			140,795
Depreciation and amortization		226,641			229,264			455,313			453,987
Taxes (other than income taxes)		99,632			92,489			205,256			189,059
Total operating expenses		1,868,978			2,078,780			4,066,895			4,468,657
Operating income		405,690			359,442			785,852			786,105
Other income, net		728			979			4,465			5,745
Equity earnings of unconsolidated subsidiaries		7,502			7,677			14,660			15,390
Allowance for funds used during construction — equity		15,194			13,606			28,644			26,850
Interest charges and financing costs
Interest charges — includes other financing costs of $6,036, $6,185, $12,116 and $11,445, respectively		151,921			146,338			303,751			290,692
Allowance for funds used during construction — debt		(7,683	)		(7,838	)		(14,290	)		(15,274	)
Total interest charges and financing costs		144,238			138,500			289,461			275,418
Income from continuing operations before income taxes		284,876			243,204			544,160			558,672
Income taxes		101,801			84,533			177,316			196,534
Income from continuing operations		183,075			158,671			366,844			362,138
(Loss) income from discontinued operations, net of tax		(15	)		91			109			193
Net income		183,060			158,762			366,953			362,331
Dividend requirements on preferred stock		-			1,060			-			2,120
Earnings available to common shareholders	$	183,060		$	157,702		$	366,953		$	360,211
Weighted average common shares outstanding:
Basic		487,717			484,918			487,538			484,283
Diluted		488,017			485,241			488,006			484,775
Earnings per average common share:
Basic	$	0.38		$	0.33		$	0.75		$	0.74
Diluted		0.38			0.33			0.75			0.74
Cash dividends declared per common share	$	0.27		$	0.26		$	0.53		$	0.51

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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 June 30						Six Months Ended June 30
Diluted Earnings (Loss) Per Share	2012			2011			2012			2011
Public Service Company of Colorado (PSCo)	$	0.20		$	0.15		$	0.39		$	0.35
NSP-Minnesota		0.13			0.13			0.29			0.32
Southwestern Public Service Company (SPS)		0.06			0.05			0.08			0.07
NSP-Wisconsin		0.01			0.02			0.04			0.05
Equity earnings of unconsolidated subsidiaries		0.01			0.01			0.02			0.02
Regulated utility — continuing operations (a)		0.41			0.36			0.82			0.81
Xcel Energy Inc. and other costs		(0.03	)		(0.03	)		(0.07	)		(0.07	)
GAAP diluted earnings per share	$	0.38		$	0.33		$	0.75		$	0.74

(a) See Note 2.

PSCo — PSCo earnings increased $0.05 per share during the second quarter of 2012 and $0.04 per share for the six months ended June 30, 2012.  The increases are primarily due to an electric rate increase effective in May 2012, lower operating and maintenance (O&M) expenses and the impact of warmer summer weather.  The increases were partially offset by decreased wholesale revenue due to the expiration of a long-term wholesale power agreement with Black Hills Corp.

NSP-Minnesota — NSP-Minnesota earnings were flat for the second quarter of 2012 and decreased $0.03 per share for the six months ended June 30, 2012.  The year-to-date decrease is primarily due to the unfavorable impact of warmer than normal winter weather, higher property taxes, higher O&M expenses and sluggish electric sales, which were partially offset by the positive impact of summer weather and a lower effective tax rate.

SPS — SPS earnings increased $0.01 per share in both the second quarter of 2012 and the six months ended June 30, 2012.  The increases are the result of rate increases in New Mexico and Texas, effective January 2012, partially offset by higher depreciation expense due to Jones Unit 3 going into service in June 2011 and higher property taxes.

NSP-Wisconsin — NSP-Wisconsin earnings decreased $0.01 per share in both the second quarter of 2012 and the six months ended June 30, 2012.  The decreases are primarily attributable to the impact of warmer winter weather and higher O&M expenses, partially offset by rate increases effective in January 2012 and the impact of warmer summer weather.

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The following table summarizes significant components contributing to the changes in the 2012 EPS compared with the same periods in 2011, which are discussed in more detail later in the release.

	Three Months			Six Months
Diluted Earnings (Loss) Per Share	Ended June 30			Ended June 30
2011 GAAP diluted earnings per share	$	0.33		$	0.74
Components of change — 2012 vs. 2011
Higher electric margins		0.05			0.02
Lower conservation and DSM expenses (generally offset in revenues)		0.01			0.02
Higher interest charges		(0.01	)		(0.02	)
Higher taxes (other than income taxes)		(0.01	)		(0.02	)
Lower effective tax rate		-			0.03
Lower natural gas margins		-			(0.02	)
Other, net		0.01			-
2012 GAAP diluted earnings per share	$	0.38		$	0.75

Note 2.  Regulated Utility Results — Continuing Operations

Estimated Impact of Temperature Changes on Regulated Earnings — Unusually 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 provided in the following table:

	Three Months Ended June 30									Six Months Ended June 30
	2012 vs. Normal			2011 vs. Normal			2012 vs. 2011			2012 vs. Normal			2011 vs. Normal			2012 vs. 2011
HDD		(33.1	) %		0.9	%		(34.5	) %		(21.4	) %		4.4	%		(24.3	) %
CDD		79.9			33.9			34.3			83.2			33.5			37.6
THI		40.1			(6.4	)		49.7			45.7			(6.5	)		55.8

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

	Three Months Ended June 30								Six Months Ended June 30
	2012 vs. Normal			2011 vs. Normal		2012 vs. 2011			2012 vs. Normal			2011 vs. Normal		2012 vs. 2011
Retail electric	$	0.032		$	0.004	$	0.028		$	0.007		$	0.011	$	(0.004	)
Firm natural gas		(0.008	)		0.001		(0.009	)		(0.029	)		0.008		(0.037	)
Total	$	0.024		$	0.005	$	0.019		$	(0.022	)	$	0.019	$	(0.041	)

Sales Growth (Decline)— The following table summarizes Xcel Energy’s sales growth (decline) for actual and weather-normalized sales in 2012:

	Three Months Ended June 30
	Actual			Weather Normalized
Electric residential		2.5	%		(0.8	) %
Electric commercial and industrial		2.3			1.1
Total retail electric sales		2.3			0.5
Firm natural gas sales		(25.9	)		(4.3	)

							Six Months Ended June 30
	Six Months Ended June 30						(Without Leap Day)
	Actual			Weather Normalized			Actual			Weather Normalized
Electric residential		(1.6	) %		(0.1	) %		(2.1	) %		(0.7	) %
Electric commercial and industrial		0.8			0.6			0.3			0.1
Total retail electric sales		0.1			0.4			(0.4	)		(0.2	)
Firm natural gas sales		(17.4	)		(0.1	)		(18.1	)		(0.9	)

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 June 30						Six Months Ended June 30
(Millions of Dollars)	2012			2011			2012			2011
Electric revenues	$	2,037		$	2,128		$	3,974		$	4,158
Electric fuel and purchased power		(854	)		(989	)		(1,718	)		(1,921	)
Electric margin	$	1,183		$	1,139		$	2,256		$	2,237

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

(Millions of Dollars)	Three Months Ended June 30 2012 vs. 2011			Six Months Ended June 30 2012 vs. 2011
Retail rate increases (Colorado, Texas, New Mexico, Wisconsin, South Dakota,
Michigan, North Dakota and Minnesota) (a)	$	25		$	31
Estimated impact of weather		21			(3	)
Transmission revenue, net of costs		4			9
Demand revenue		4			8
Conservation and DSM incentive		3			5
Firm wholesale (b)		(11	)		(22	)
Conservation and DSM revenue (offset by expenses)		(3	)		(7	)
Other, net		1			(2	)
Total increase in electric margin	$	44		$	19

(a) NSP-Minnesota reduced depreciation expense and revenues by approximately $9 million in the second quarter of 2012 and $16 million for the six months ended June 30, 2012 to reflect the settlements in the Minnesota and South Dakota electric rate cases.

(b) Decrease is primarily due to the expiration of a long-term wholesale power agreement with Black Hills Corp.

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 June 30						Six Months Ended June 30
(Millions of Dollars)	2012			2011			2012			2011
Natural gas revenues	$	221		$	292		$	842		$	1,057
Cost of natural gas sold and transported		(90	)		(163	)		(508	)		(706	)
Natural gas margin	$	131		$	129		$	334		$	351

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

(Millions of Dollars)	Three Months Ended June 30  2012 vs. 2011			Six Months  Ended June 30 2012 vs. 2011
Pipeline system integrity adjustment rider (Colorado)	$	8		$	11
Retail rate increase (Colorado, Wisconsin)		6			9
Return on PSCo gas in storage		1			4
Estimated impact of weather		(7	)		(28	)
Conservation and DSM revenue (offset by expenses)		(3	)		(12	)
Other, net		(3	)		(1	)
Total increase (decrease) in natural gas margin	$	2		$	(17	)

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O&M Expenses — O&M expenses increased $1.8 million, or 0.3 percent, for the second quarter of 2012 and $2.5 million, or 0.2 percent, for the six months ended June 30, 2012, compared with the same periods in 2011.  The higher expenses are primarily attributable to higher pension expense, partially offset by management cost savings initiatives.

Conservation and DSM Program Expenses — Conservation and demand side management (DSM) program expenses decreased $6.9 million, or 10.5 percent, for the second quarter of 2012 and $18.5 million, or 13.1 percent, for the six months ended June 30, 2012, compared with the same periods in 2011.  The lower expense is primarily attributable to lower gas rider rates, as well as the timing of recovery of electric conservation improvement program expenses at NSP-Minnesota.  Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization decreased $2.6 million, or 1.1 percent, for the second quarter of 2012 and increased $1.3 million, or 0.3 percent, for the six months ended June 30, 2012, compared with the same periods in 2011.  The change is primarily due to normal system expansion across Xcel Energy’s service territories, partially offset by a change in depreciation lives for certain assets to reflect the settlements in the Minnesota and South Dakota electric rate cases.  This change in depreciation lives resulted in a reduction in depreciation expense of approximately $9 million for the second quarter of 2012 and approximately $16 million for the six months ended June 30, 2012.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $7.1 million, or 7.7 percent, for the second quarter of 2012 and $16.2 million, or 8.6 percent, for the six months ended June 30, 2012, compared with the same periods in 2011.  The increases are due to an increase in property taxes primarily in Minnesota.  Increases in property taxes in Colorado related to the electric retail business are being deferred, based on the multi-year rate settlement that was approved by the Colorado Public Utilities Commission (CPUC) in 2012.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $1.4 million, or 6.7 percent, for the second quarter of 2012 and $0.8 million, or 1.9 percent, for the six months ended June 30, 2012, compared with the same periods in 2011.  The increases are primarily due to the expansion of PSCo’s transmission facilities, additional construction related to the Clean Air Clean Jobs Act and normal system expansion.

Interest Charges — Interest charges increased $5.6 million, or 3.8 percent, for the second quarter of 2012 and $13.1 million, or 4.5 percent, for the six months ended June 30, 2012, compared with the same periods in 2011.  The increases are due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $17.3 million for the second quarter of 2012, compared with the same period in 2011.  The increase in income tax expense was primarily due to an increase in pretax income in 2012.  The effective tax rate was 35.7 percent for the second quarter of 2012 compared with 34.8 percent for the same period in 2011.  The higher effective tax rate for 2012 was primarily due to a higher forecasted annual effective tax rate, which was mainly attributable to increased state income taxes in 2012.

Income tax expense decreased $19.2 million for the first six months of 2012, compared with the same period in 2011.  The decrease in income tax expense was primarily due to lower pretax earnings and a tax benefit associated with a carryback. The effective tax rate for continuing operations was 32.6 percent for the six months ended June 30, 2012 compared with 35.2 percent for the same period in 2011.  The lower effective tax rate for 2012 was primarily due to the completion of an analysis in the first quarter on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period.  As a result, Xcel Energy recognized a discrete tax benefit of approximately $15 million.  Without this tax benefit, the effective tax rate would have been 35.3 percent for the six months ended June 30, 2012.

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

Following is the capital structure of Xcel Energy:

(Billions of Dollars)	June 30, 2012		Percentage of Total Capitalization
Current portion of long-term debt	$	1.3	7	%
Short-term debt		0.5	3
Long-term debt		8.7	45
Total debt		10.5	55
Common equity		8.6	45
Total capitalization	$	19.1	100	%

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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.  In June 2012, SPS issued $100 million of first mortgage bonds.  Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following during the remainder of 2012:

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

· PSCo may issue approximately $800 million of first mortgage bonds in the third quarter 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.

Credit Facilities — In July 2012, NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. entered into amended five-year credit agreements with a syndicate of banks, replacing their previous four-year credit agreements. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with an improvement in pricing and an extension of maturity from March 2015 to July 2017.

As of July 30, 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	$	462.0	$	338.0	$	0.4	$	338.4	July 2017
PSCo		700.0		41.0		659.0		1.0		660.0	July 2017
NSP-Minnesota		500.0		8.7		491.3		0.9		492.2	July 2017
SPS		300.0		-		300.0		0.3		300.3	July 2017
NSP-Wisconsin		150.0		113.0		37.0		1.0		38.0	July 2017
Total	$	2,450.0	$	624.7	$	1,825.3	$	3.6	$	1,828.9

 (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 July 30, 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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Note 4.  Rates and Regulation

NSP-Minnesota – Minnesota Property Tax Deferral Request — In December 2011, NSP-Minnesota filed a request to defer incremental 2012 property taxes that would not be recovered in base rates, estimated to be approximately $24 million, or alternatively that a property tax rider be approved.  In June 2012, the Minnesota Public Utilities Commission (MPUC) denied NSP-Minnesota’s request for deferred accounting for incremental property taxes and also denied the request for a property tax rider.  There were no incremental 2012 property taxes deferred as a regulatory asset.

NSP-Minnesota – South Dakota 2011 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 was based on a 2010 historic test year adjusted for known and measurable changes, a requested return on equity (ROE) of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  On Jan. 2, 2012, interim rates of $12.7 million were implemented.   In June 2012, the SDPUC authorized a rate increase of approximately $8.0 million, based on an ROE of 9.25 percent, and an equity ratio of 53 percent.  On July 17, 2012, the SDPUC approved implementation of final rates on Aug. 1, 2012, with refunds to be issued in September 2012.

NSP-Minnesota – South Dakota 2012 Electric Rate Case—On June 29, 2012, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $19.4 million annually.  The request was based on a 2011 historic test year adjusted for certain known and measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an average rate base of $367.5 million and an equity ratio of 52.89 percent.  A SDPUC decision is expected in late 2012 or early 2013.

NSP-Wisconsin – 2012 Electric and Gas Rate Case — On June 1, 2012, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) to increase rates for electric and natural gas service effective Jan. 1, 2013.  NSP-Wisconsin requested an overall increase in annual electric rates of $39.1 million, or 6.7 percent, and an increase in natural gas rates of $5.3 million, or 4.9 percent.

The electric rate filing was based on a 2013 forecast test year, a return on equity of 10.40 percent, an equity ratio of 52.50 percent and an average 2013 electric rate base of approximately $788.6 million.  The natural gas rate request was solely due to a proposal to recover the initial costs associated with the environmental cleanup of a site in Ashland, Wis., which includes the site of a former manufactured gas plant that was owned by a predecessor company to NSP-Wisconsin.  A PSCW decision is anticipated in the fourth quarter of 2012.

PSCo – SmartGridCity™ (SGC) Cost Recovery —As part of its 2010 electric rate case, PSCo requested recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred to develop and operate SGC.  In February 2011, the CPUC allowed recovery of approximately $28 million of the capital cost and 100 percent of the O&M costs.

In December 2011, PSCo requested CPUC approval for the recovery of the remaining capital investment in SGC and also provided the additional information requested.  In June 2012, the City of Boulder and the Colorado Office of Consumer Counsel filed testimony and recommend the CPUC deny PSCo’s request for recovery of the remaining portion of the SGC investment.  A decision is expected in the third quarter of 2012.

Note 5.  PSCo 2011 Electric Resource Plan

In July 2012, PSCo filed two separate applications which, if approved, would update the existing resources considered in its Resource Plan.  The first is an application to purchase Brush Power, LLC and all of its assets including Brush generating Units 1, 3 and 4 for a total purchase price of approximately $75 million.  Located in Brush, Colo., the generating units have a total capacity of 237 megawatts (MW), including Brush Unit 1, a 60 MW combined-cycle unit; Brush Unit 3, a 30 MW simple-cycle unit; and Brush Unit 4, a 147 MW combined-cycle unit. The purchase is subject to various regulatory approvals including that of the CPUC.  The Brush units currently provide energy and capacity to PSCo under purchased power agreements that are set to expire in 2017 for Brush Unit 1 and Brush Unit 3, and 2022 for Brush Unit 4.  The transaction, if approved, is expected to result in savings to wholesale and retail customers.

The second application seeks approval to retire Arapahoe Unit 4, a 109 MW coal-fired company-owned generating station at the end of 2013.  This would be an alternative to permanently fuel switching Arapahoe Unit 4 to natural gas and instead replacing the capacity and associated energy with a natural gas purchased power agreement with an existing generator.  A decision on both applications is expected between December 2012 and March 2013.

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Note 6.  Xcel Energy Earnings Guidance

Xcel Energy’s 2012 earnings is expected to be in the lower half of the guidance range of $1.75 to $1.85 per share.  Key assumptions related to earnings are detailed below:

· Constructive outcomes in all remaining rate case and regulatory proceedings.

· Normal weather patterns are experienced for the remainder of the year.

· Weather-adjusted retail electric utility sales are projected to be relatively flat.

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

· Rider revenue recovery is projected to increase approximately $35 million to $45 million over 2011 levels.

· O&M expenses are projected to increase up to 1.0 percent over 2011 levels.

· Depreciation and amortization expense is projected to increase $40 million to $50 million over 2011 levels.

· Property taxes are projected to increase $25 million to $30 million over 2011 levels.

· Interest expense (net of AFUDC — debt) is projected to increase approximately $10 million.

· AFUDC — equity is projected to increase approximately $10 million to $20 million over 2011 levels.

· The effective tax rate is projected to be approximately 34 percent to 35 percent.

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

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XCEL ENERGY INC. AND SUBSIDIARIES

EARNINGS RELEASE SUMMARY (Unaudited)

(amounts in thousands, except per share data)

	Three Months Ended June 30
	2012			2011
Operating revenues:
Electric and natural gas revenues	$	2,258,142		$	2,419,935
Other		16,526			18,287
Total operating revenues		2,274,668			2,438,222
Income from continuing operations		183,075			158,671
(Loss) income from discontinued operations		(15	)		91
Net income	$	183,060		$	158,762
Earnings available to common shareholders	$	183,060		$	157,702
Weighted average diluted common shares outstanding		488,017			485,241
Components of Earnings per Share — Diluted
Regulated utility — continuing operations	$	0.41		$	0.36
Xcel Energy Inc. and other costs		(0.03	)		(0.03	)
GAAP diluted earnings per share	$	0.38		$	0.33

	Six Months Ended June 30
	2012			2011
Operating revenues:
Electric and natural gas revenues	$	4,815,959		$	5,215,256
Other		36,788			39,506
Total operating revenues		4,852,747			5,254,762
Income from continuing operations		366,844			362,138
Income from discontinued operations		109			193
Net income	$	366,953		$	362,331
Earnings available to common shareholders	$	366,953		$	360,211
Weighted average diluted common shares outstanding		488,006			484,775
Components of Earnings per Share — Diluted
Regulated utility — continuing operations	$	0.82		$	0.81
Xcel Energy Inc. and other costs		(0.07	)		(0.07	)
GAAPdiluted earnings per share		0.75			0.74
Book value per share	$	17.59		$	16.99

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