Exhibit 99.1

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West Coast Investor Meetings

September 20-21, 2005

Safe Harbor

This material includes forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements include projected earnings, cash flows, capital expenditures and other statements and are identified in this document by the words “anticipate,” “estimate,” “expect,” “projected,” “objective,” “outlook,” “possible,” “potential” and similar expressions.  Actual results may vary materially.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit, actions of rating agencies and their impact on capital expenditures; business conditions in the energy industry; competitive factors; unusual weather; effects of geopolitical events, including war and acts of terrorism; changes in federal or state legislation; regulation; final approval and implementation of the pending settlement of the securities, ERISA and derivative litigation; costs and other effects of legal administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; risks associated with the California power market; the higher degree of risk associated with Xcel Energy’s nonregulated businesses compared with Xcel Energy’s regulated business; and other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including Exhibit 99.01 to Xcel Energy’s report on Form 10-K for year 2004.

Strategy — Building the Core

Invest in utility assets

AND

Earn our allowed return on equity

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Drivers to Value Creation

			Earn Authorized Return
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		Increase Equity
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	Increase Investment
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Service Territory Growth
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Potential Regulatory Income and Depreciation*

				Potential	Growth
				Result	Rate
	2004			2009	2004-2009
Average rate base	$	10.5	B	$13 B	4.4	%
Regulatory equity ratio	50.4		%	50 – 52%
Equity rate base	$	5.3	B	$6.5 – 6.76 B
Regulatory return on equity	9.6		%	10 – 11%
Regulatory net income	$	506	M	$650 – $744 M	5 – 8	%
Depreciation – Cash flow	$	735	M	$910 M**
Potential net income and depreciation from regulated operations	$	1,241	M	$1,560 – $1,654 M

*	All figures except 2004 depreciation are on an estimated regulatory basis, which differs from GAAP reporting. A reconciliation from GAAP reporting is shown in the appendix.
**	Assumes depreciation grows at the same rate as rate base.

Capital Expenditure Plan

•Prudent

•Have regulatory, legislative and environmental support

•Manageable

•Add to earnings growth

•Deliver stronger credit metrics

Regulatory, Legislative and Environmental Support

•Minnesota MERP rider

•Comanche 3 decision — Forward CWIP and higher equity

•Minnesota and Texas transmission investment legislation

Capital Expenditure Forecast

Dollars in millions

	2005			2006			2007			2008			2009			Total
Total	$	1,241		$	1,500		$	1,505		$	1,352		$	1,266		$	6,864
	Anticipated annual growth in average rate base
																Average
	2005			2006			2007			2008			2009			Annual
2004 Rate base $10.5 billion	4		%	4		%	7		%	5		%	2		%	4.4		%

Sources of Funding

•Growing cash from operations

•Tax loss carry-forward

•Proceeds from asset sales

•Financing:

•Dividend reinvestment program

•Modest debt issuance

•No equity issuance necessary through 2006

•Uncertain whether there is a need for public equity issuance in 2007 or 2008

Rate Cases with Potential Revenue Increases Effective in 2006

•Colorado Gas – Requested $34 million

•Wisconsin Electric and Gas – Requested $48 million

•Minnesota Electric

•North Dakota Electric

Rate Cases with Potential Revenue Increases Effective in 2007

•Colorado Electric

•South Dakota Electric

•Texas Electric

•New Mexico Electric

Regulatory Net Income Growth Potential

							Annual
				2005 – 2009			Growth
	2004			Potential			Rate
Rate base	$	10.5	B	$	13	B	4.4	%
Utility equity capitalization	50		%	50 – 52		%	0 to 0.8	%
Earned return on utility rate base equity	9.6		%	10 – 11		%	0 to 2.6	%
Total potential growth							4.4 to 7.8	%

Company-Owned Life Insurance (COLI)

•IRS dispute over tax deductibility of COLI

•$350 million potential exposure for tax and interest

•$65 million potential exposure for penalties

•2005 guidance includes $40 million tax benefit or 9 cents per share for COLI

•It will potentially take several years to resolve

•Potential FASB financial reporting issue

•Exposure draft issued on uncertain tax positions
•Impacts financial reporting not cash flows

2005 EPS Guidance Continuing Operations*

	2005
	Guidance
Regulated utility	$	1.27 – 1.37
Holding Company & other	(0.09		)
Total earnings from continuing operations	$	1.18 – 1.28

* 2005 Guidance includes COLI tax benefits of 9 cents per share

Dividend

•Annual dividend increased by 3 cents May 2005

•Current annual dividend rate of 86 cents

•Annual dividend increases consistent with long-term earnings growth of 2 – 4%

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Transparent Low-Risk Strategy

•Constructive legislative & regulatory climate

•Strategy delivers:

•Competitive total return to shareholders

•Improving credit metrics

Appendix

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4^th largest US electric and gas utility —

Customers:

3.3 Million Electric
1.8 Million Gas

Strong Regional Economy

Unemployment rate — February 2005
US	5.8	%
Xcel service area	4.7	%
Job growth – 2005 Forecast
Xcel service area	2.4	%
Xcel annual sales growth — 2005-2009
Electric	2.0	%
Gas	1.2	%

Organizational Structure 2004 Results

		Xcel Energy Inc. $527	Income from Continuing Operations (Dollars in millions)
		Holding Company $(43)
Northern States Power Company - Minnesota	Northern States Power Company - Wisconsin	Public Service Company of Colorado	Southwestern Public Service Company	Subsidiaries •Eloigne •Quixx
$230	$54	$218	$55	$13
Regulated				Nonregulated

Rate Base and Returns

Dollars in millions

	Rate Base			Earned				Equity
	2004			ROE		Authorized		Ratio
	Average			2004		ROE		2004
Minnesota - Electric retail	$	2,992		10.73	%	11.47	%	50.3	%
Minnesota - Gas retail	402			8.50		11.40		50.3
North Dakota - Electric retail	166			10.80		12.00		50.3
North Dakota - Gas retail	39			8.18		11.50		47.6
Colorado - Electric retail	3,042			9.18		10.75		50.1
Colorado - Gas retail	996			8.76		11.00		50.1
Texas -Electric retail	889			9.39		11.50		48.7
NSP (W) - Retail electric	538			NR		11.90		55.8
NSP (W) - Retail gas	70			NR		11.90		55.8
Non-reported	1.4		B
Total including non-reported	10.5		B

NR:  Non-reportable

Reconciliation of Estimated Regulatory Reporting from GAAP

Dollars in millions

Common Equity

	NSP (M)		NSP (W)		PSCo		SPS		Total
2004 GAAP common stockholder’s equity (1)	$	2,007	$	433	$	2,287	$	781	$	5,507
2003 GAAP common stockholder’s equity (1)	1,809		425		2,140		814		5,188
Average GAAP common stockholder’s equity	1,908		429		2,213		798		5,348
Adjustments	-5		-5		64		-11		43
Adjusted average equity for purposes of regulatory equity ratio	$	1,903	$	424	$	2,277	$	787	$	5,391

Debt

Source: 2004 Operating Company 10-K’s

	NSP (M)		NSP (W)		PSCo		SPS		Total
2004 GAAP total debt (1) (2)	$	2,032	$	348	$	2,502	$	861	$	5,743
2003 GAAP total debt (1) (2)	2,003		337		1,845		825		5,010
Average GAAP total debt	2,018		342		2,173		843		5,376
Adjustments	-140		-6		94		-16		-68
Adjusted average debt for purposes of regulatory equity ratio	$	1,878	$	336	$	2,267	$	827	$	5,308
Regulatory equity ratio									50.4		%

(1)Source: 2004 Operating Company 10-K’s

(2)Consists of long-term debt, current portion of long-term debt and short-term debt

See note on the bottom of the following page for additional information

Dollars in millions

Net Income

	NSP (M)		NSP (W)		PSCo		SPS		Total
2004 GAAP net income (1)	$	230	$	54	$	218	$	55	$	557
Adjustments	-25				-26				-51
Adjusted net income for purposes of regulatory net income	$	205	$	54	$	192	$	55	$	506

Calculation of Regulatory Net Income

Estimated regulatory rate base ($10.5 B) x Regulatory equity ratio (50.4%)
= Estimated equity rate base ($5.3 B)

Regulatory net income ($506 M) ÷ Estimated equity rate base ($5.3 B) = Estimated regulatory
return on equity (9.6%)

Depreciation & Amortization – Cash Flows

	NSP (M)		NSP (W)		PSCo		SPS		Total
2004 GAAP depreciation and amortization – cash flow (1)	$	352	$	48	$	234	$	100	$	735

(1)Source: 2004 Operating Company 10-K’s

Financial results for regulatory reporting frequently differ from GAAP.

Regulatory reporting includes the use of 12 and 13 month averages for capitalization, eliminates inter-company transactions, excludes non-regulated investments, includes or excludes revenues and or expenses associated with various recovery mechanisms and other factors, all of which may vary from one regulatory jurisdiction to another.

NSP — Minnesota Rate Cases

North Dakota Gas	Approved June	$0.7 million increase
Minnesota Gas	Approved July 10.4% ROE	$5.8 million increase
Minnesota Electric	To be filed Winter 2005 2006 test year Interim rates early 2006 Decision Summer 2006
North Dakota Electric	To be filed Winter 2005 Interim rates early 2006 Decision Summer 2006
South Dakota Electric	To be filed mid-2006 Decision 2007

PSCo Rate Cases

Colorado Gas	Filed May 27 Requested $34 million 11% ROE 55.49% common equity Year-end rate base Decision early 2006
Colorado Electric	To be filed Spring 2006 Decision early 2007

Wisconsin Electric and Gas Rate Case

Requested ROE 11.9%

Common equity ratio 56.32%

Electric requested:  Revenue increase of $40.8 million

Gas requested:  Revenue increase of $7.0 million

Rates expected to be in effect January 2006

SPS Rate Case

Texas Electric	To be filed Summer 2006 Decision 2007
New Mexico Electric	To be filed 2006 Decision 2007

Capital Expenditures $6.9 Billion 2005 – 2009

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Capital Expenditure Forecast

Dollars in millions

	2005		2006		2007		2008		2009
Minnesota MERP	$	191	$	404	$	197	$	125	$	56
Comanche 3	59		179		287		298		125
Base level capital expenditures	991		917		1,021		929		1,085
Total	$	1,241	$	1,500	$	1,505	$	1,352	$	1,266

Capital Expenditure Forecast by Operating Company

Dollars in millions

	2005		2006		2007		2008		2009
NSP-Minnesota	$	645	$	832	$	713	$	571	$	605
NSP-Wisconsin	60		79		75		74		68
PSCo	425		499		593		591		488
SPS	111		90		124		116		105
Total	$	1,241	$	1,500	$	1,505	$	1,352	$	1,266

NSP — Minnesota Operating Company Capital Expenditure Forecast

Dollars in millions

	2005		2006		2007		2008		2009		Total
MERP	$	191	$	404	$	197	$	125	$	56	$	973
Excluding MERP	454		428		516		446		549		2,393
Total	$	645	$	832	$	713	$	571	$	605	$	3,366
					MERP						$	973
					Transmission						459
					Nuclear fuel						336
					Balance of electric						1,250
					Gas						188
					Common						160
					Total						$	3,366

PSCo Operating Company Capital Expenditure Forecast

Dollars in millions

	2005		2006		2007		2008		2009		Total
Comanche 3	$	59	$	179	$	287	$	298	$	125	$	948
Excl. Comanche 3	366		320		306		293		363		1,648
Total	$	425	$	499	$	593	$	591	$	488	$	2,596
					Comanche 3						$	948
					Transmission						280
					Balance of electric						809
					Gas						438
					Common						98
					Thermal						16
					Non-utility						7
					Total						$	2,596

SPS Operating Company Capital Expenditure Forecast

Dollars in millions

	2005		2006		2007		2008		2009		Total
Total	$	111	$	90	$	124	$	116	$	105	$	546
			Transmission								$	140
			Balance of electric								406
			Total electric								$	546

NSP — Wisconsin Operating Company Capital Expenditure Forecast

Dollars in millions

	2005		2006		2007		2008		2009		Total
Total	$	60	$	79	$	75	$	74	$	68	$	356
			Transmission								$	73
			Balance of electric								200
			Gas								45
			Common								38
			Total								$	356

Minnesota MERP —  Potential Earnings

Dollars in millions

	2005				2006			2007			2008			2009
Capital expenditures
Current year	$	191			$	404		$	197		$	125		$	56
Cumulative	$	238			$	642		$	839		$	964		$	1,020
Equity ratio	48.5			%	48.5		%	48.5		%	48.5		%	48.5		%
Return on equity	10.86			%	10.86		%	10.86		%	10.86		%	10.86		%
Equity return	$		8		$	24		$	40		$	48		$	53

Comanche 3 — Potential Earnings

Dollars in Millions

	2005			2006			2007			2008			2009
Capital expenditures
Current year	$	59		$	179		$	287		$	298		$	125
Cumulative	$	62		$	241		$	528		$	826		$	951
Equity ratio	56		%	56		%	56		%	56		%	56		%
Return on equity	10.75		%	10.75		%	10.75		%	10.75		%	10.75		%
Equity return	$	2		$	9		$	23		$	41		$	54

Energy Supply Mix — 2004 Owned and Purchased

Fuel Mix	Purchased Energy
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*  Low-sulfur, low-mercury western coal

Coal Supply Contracted

			Coal
	Coal		Transportation
2005	99	%	100	%
2006	78		75
2007	65		45
2008	46		45

Annual consumption:  32 Million tons of low-sulfur, low-mercury western coal

Electric Fuel and Purchased Energy Cost Recovery Mechanisms

Minnesota:	Monthly recovery of prospective costs
Colorado:	Recovery of costs with sharing of deviations up to + $11.25 million from benchmark
Texas:	File for semi-annual adjustments – required if + 4% annually
Wisconsin:	Biennial rate case – file for interim adjustment if costs fall outside+ 2% annually
New Mexico:	Recovery of costs with 2 month lag

Retail Electric Rate* Comparison

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Senior Debt Ratings

	Moody’s		S&P
	Secured	Unsecured	Secured		Unsecured
Holding Co.	—	Baa1	—		BBB	-
NSPM	A2	A3	A	-	BBB	-
NSPW	A2	A3	A	-	BBB
PSCo	A3	Baa1	A	-	BBB	-
SPS	—	Baa1	—		BBB
Outlook		Stable			Stable