Exhibit 99.01

414 Nicollet Mall

Minneapolis, MN 55401

January 31, 2007

Investor Relations Earnings Release

Xcel Energy Announces 2006 Earnings

MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) announced income from continuing operations of $569 million, or $1.35 per share on a diluted basis, for 2006, compared with $499 million, or $1.20 per share in 2005.

Total earnings for the year, which include the impact of discontinued operations, were $572 million or $1.36 per share, compared with $513 million or $1.23 per share in 2005.

Xcel Energy’s earnings for 2006 included the following:

·Regulated utility income from continuing operations was $606 million, or $1.41 per share, compared with $539 million, or $1.27 per share, in 2005;

·Holding company charges from continuing operations were $26 million, or 6 cents per share, compared with $30 million, or 7 cents per share in 2005; and

·Discontinued operations income was $3 million, or 1 cent per share, compared with income of $14 million, or 3 cents per share, in 2005.

Increased earnings for 2006 were primarily due to a stronger base electric utility margin. The higher margin reflects electric rate increases in various jurisdictions, weather-adjusted retail electric sales growth and revenue associated with investments in the Metropolitan Emissions Reduction Project. In addition, earnings increased due to the recognition of income tax benefits. Partially offsetting these positive factors were expected increases in expenses for operations, maintenance and depreciation and lower short-term wholesale margins.

“On many fronts, 2006 was an outstanding year,” said Richard C. Kelly, chairman, president and chief executive officer. “We realized earnings at the top of our guidance range. Constructive conclusions were reached in our electric rate cases in both Minnesota and Colorado. Customer service reliability has improved compared to the previous year. Construction of our major projects is running smoothly and both the Metropolitan Emissions Reduction Project and the Comanche 3 coal-fired power plant in Colorado remain on track.

“The results achieved in 2006 are further evidence that our Build the Core strategy is working for both our shareholders and customers. We will continue to invest in projects that meet our customers’ needs, including potential projects to reduce emissions and extend the life of our Sherco plant, to own wind generation and to invest in natural gas transmission and storage facilities. Our guidance for 2007 continues to be $1.35 to $1.45 per share, and we remain confident we can grow earnings 5 to 7 percent annually on a normalized basis.”

1

At 9 a.m. CT today, Xcel Energy will host a conference call to review 2006 financial results. To participate in the conference call, please dial in five to 10 minutes prior to the scheduled start and follow the operator’s instructions.

US Dial-In:	(800) 374-0832
International Dial-In:	(706) 634-5081

The conference call also will be simultaneously broadcast and archived on Xcel Energy’s Web site 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 12 p.m. CT on Jan. 31 through 11:59 p.m. CT on Feb. 2.

Replay Numbers

US Dial-In:	(800) 642-1687
International Dial-In:	(706) 645-9291
Conference ID:	5140555

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis 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. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; 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 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; 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 of accounting regulatory bodies; 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 Cautionary Factors in Exhibit 99.01 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005.

For more information, contact:

P A Johnson               Managing Director, Investor Relations                                  (612) 215-4535

For news media inquiries only, please call Xcel Energy media relations    (612) 215-5300

Xcel Energy Internet address:

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)

(Thousands, Except Per Share Data)

	Three months ended				Twelve months ended
	Dec. 31,				Dec. 31,
	2006		2005		2006		2005
Operating revenues:
Electric utility	$	1,815,731	$	1,922,362	$	7,608,018	$	7,243,637
Natural gas utility	636,576		938,764		2,155,999		2,307,385
Nonregulated and other	14,429		21,111		76,287		74,455
Total operating revenues	2,466,736		2,882,237		9,840,304		9,625,477
Operating expenses:
Electric fuel and purchased power — utility	996,251		1,124,671		4,103,055		3,922,163
Cost of natural gas sold and transported — utility	488,674		794,806		1,644,716		1,823,123
Cost of sales — nonregulated and other	7,626		7,513		24,388		24,676
Other operating and maintenance expenses — utility	453,874		438,315		1,743,457		1,679,172
Other operating and maintenance expenses — nonregulated	9,599		7,348		30,069		28,493
Depreciation and amortization	206,916		191,853		821,898		767,321
Taxes (other than income taxes)	74,314		67,176		295,727		287,810
Total operating expenses	2,237,254		2,631,682		8,663,310		8,532,758
Operating income	229,482		250,555		1,176,994		1,092,719
Interest and other income (expense) — net	1,399		(3,508)		4,085		857
Allowance for funds used during construction — equity	8,294		6,730		25,045		21,627
Interest charges and financing costs:
Interest charges — (includes other financing costs of $5,417, $6,506, $24,187 and $25,829, respectively)	126,595		117,912		486,967		463,370
Allowance for funds used during construction — debt	(8,690)		(6,397)		(30,935)		(20,744)
Total interest charges and financing costs	117,905		111,515		456,032		442,626
Income from continuing operations before income taxes	121,270		142,262		750,092		672,577
Income taxes	24,512		43,298		181,411		173,539
Income from continuing operations	96,758		98,964		568,681		499,038
Income from discontinued operations — net of tax	960		13,104		3,073		13,934
Net income	97,718		112,068		571,754		512,972
Dividend requirements on preferred stock	1,060		1,060		4,241		4,241
Earnings available for common shareholders	$	96,658	$	111,008	$	567,513	$	508,731
Weighted average common shares outstanding (in thousands):
Basic	407,037		403,229		405,689		402,330
Diluted	431,156		426,570		429,605		425,671
Earnings per share — basic:
Income from continuing operations	$	0.24	$	0.25	$	1.39	$	1.23
Income from discontinued operations	—		0.03		0.01		0.03
Total	$	0.24	$	0.28	$	1.40	$	1.26
Earnings per share — diluted:
Income from continuing operations	$	0.23	$	0.24	$	1.35	$	1.20
Income from discontinued operations	—		0.03		0.01		0.03
Total	$	0.23	$	0.27	$	1.36	$	1.23

3

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Investor Relations 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.

Note 1. Earnings per Share Summary

The following table summarizes the earnings-per-share contributions of Xcel Energy’s businesses.

	Three months ended						Twelve months ended
	Dec. 31,						Dec. 31,
Earnings (Loss) Per Share	2006			2005			2006			2005
Regulated utility segments — continuing operations — Note 2	$	0.27		$	0.27		$	1.41		$	1.27
Holding company costs and other	(0.04		)	(0.03		)	(0.06		)	(0.07		)
Earnings per share — continuing operations	0.23			0.24			1.35			1.20
Income from discontinued operations	—			0.03			0.01			0.03
Total earnings per share — diluted	$	0.23		$	0.27		$	1.36		$	1.23

The following table summarizes significant components contributing to the changes in the fourth quarter and year-to-date 2006 earnings per share compared with the same periods in 2005, which are discussed in more detail later in the release.

	Three months ended			Twelve months ended
	Dec. 31,			Dec. 31,
2005 Earnings per share — diluted	$	0.27		$	1.23
Components of change — 2006 vs. 2005
Higher base electric utility margins	0.05			0.33
Higher natural gas margins	0.01			0.04
Higher utility operating and maintenance expense	(0.02		)	(0.09		)
Higher depreciation and amortization expense	(0.02		)	(0.08		)
Lower short-term wholesale and commodity trading margins	(0.02		)	(0.06		)
Other	(0.01		)	0.01
Net change in earnings per share — continuing operations	(0.01		)	0.15
Changes in Earnings Per Share — Discontinued Operations	(0.03		)	(0.02		)
2006 Earnings per share — diluted	$	0.23		$	1.36

Note 2. Regulated Utility Segment Results — Continuing Operations

Estimated Impact of Temperature Changes on Regulated Earnings — The following summarizes the estimated impact of temperature variations on utility results included in continuing operations, compared with sales under normal weather conditions.

	Three months ended								Twelve months ended
	Dec. 31,								Dec. 31,
	2006 vs. Normal			2005 vs. Normal		2006 vs. 2005			2006 vs. Normal			2005 vs. Normal			2006 vs. 2005
Retail electric	($0.01		)	$	0.00	($0.01		)	$	0.04		$	0.04		$	0.00
Firm natural gas	$	0.00		$	0.00	$	0.00		($0.02		)	($0.01		)	($0.01		)
Total	($0.01		)	$	0.00	$	(0.01	)	$	0.02		$	0.03		($0.01		)

4

Sales Growth —The following table summarizes Xcel Energy’s regulated utility growth from continuing operations for actual and weather-normalized energy sales for the three- and 12-month periods ended Dec. 31, 2006, compared with the same periods in 2005.

	Three months ended Dec. 31,				Twelve months ended Dec. 31,
	Actual		Normalized		Actual		Normalized
Electric residential	(0.3	%)	0.3	%	0.9	%	1.4	%
Electric commercial and industrial	1.5	%	1.5	%	2.2	%	2.0	%
Total retail electric sales	1.0	%	1.2	%	1.8	%	1.8	%
Firm natural gas sales	(7.2	%)	(6.6	%)	(5.5	%)	(2.8	%)

Base Electric Utility, Short-term Wholesale and Commodity Trading Margins —  The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities that are included in continuing operations.

(Millions of Dollars)	Base Electric Utility			Short-term  Wholesale			Commodity  Trading			Consolidated Total
3 months ended 12/31/2006
Electric utility revenue (excluding commodity trading)	$	1,743		$	67		$	—		$	1,810
Electric fuel and purchased power utility	(934		)	(62		)	—			(996		)
Commodity trading revenue	—			—			90			90
Commodity trading costs	—			—			(84		)	(84		)
Gross margin before operating expenses	$	809		$	5		$	6		$	820
Margin as a percentage of revenue	46.4		%	7.5		%	6.7		%	43.2		%
3 months ended 12/31/2005
Electric utility revenue (excluding commodity trading)	$	1,872		$	44		$	—		$	1,916
Electric fuel and purchased power-utility	(1,100		)	(25		)	—			(1,125		)
Commodity trading revenue	—			—			217			217
Commodity trading costs	—			—			(211		)	(211		)
Gross margin before operating expenses	$	772		$	19		$	6		$	797
Margin as a percentage of revenue	41.2		%	43.2		%	2.8		%	37.4		%
12 months ended 12/31/2006
Electric utility revenue (excluding commodity trading)	$	7,387		$	201		$	—		$	7,588
Electric fuel and purchased power utility	(3,925		)	(178		)	—			(4,103		)
Commodity trading revenue	—			—			610			610
Commodity trading costs	—			—			(590		)	(590		)
Gross margin before operating expenses	$	3,462		$	23		$	20		$	3,505
Margin as a percentage of revenue	46.9		%	11.4		%	3.3		%	42.8		%
12 months ended 12/31/2005
Electric utility revenue (excluding commodity trading)	$	7,038		$	196		$	—		$	7,234
Electric fuel and purchased power-utility	(3,802		)	(120		)	—			(3,922		)
Commodity trading revenue	—			—			730			730
Commodity trading costs	—			—			(720		)	(720		)
Gross margin before operating expenses	$	3,236		$	76		$	10		$	3,322
Margin as a percentage of revenue	46.0		%	38.8		%	1.4		%	41.7		%

Note — The short-term wholesale and commodity trading results in the above table reflect the estimated impacts of the regulatory sharing of certain margins.

5

Base electric utility margins, which are primarily derived from retail customer sales, increased approximately $37 million for the fourth quarter of 2006, compared with the fourth quarter of 2005. Base electric utility margins increased approximately $226 million for 2006, compared with 2005. For more information see the following table:

	Three months ended Dec. 31,			Twelve months ended Dec. 31,
(Millions of Dollars)	2006 vs. 2005			2006 vs. 2005
NSP-Minnesota electric rate changes	$	33		$	129
NSP-Wisconsin rate changes, including fuel and purchased power recovery	2			41
Sales growth (excluding weather impact)	3			39
Metropolitan Emission Reduction Project (MERP) rider	9			38
Conservation and non-fuel rider revenue	6			24
Firm wholesale	4			12
Quality of service obligations	(4		)	12
Transmission fee classification change	(7		)	(26		)
PSCo electric commodity adjustment incentive	(2		)	(20		)
SPS Texas surcharge decision	(2		)	(8		)
SPS FERC 206 rate refund accrual	—			(8		)
Estimated impact of weather	(4		)	(3		)
Other, including certain regulatory reserves	(1		)	(4		)
Total base electric utility margin increase	$	37		$	226

The transmission fee classification changed from other operating and maintenance expenses-utility in 2005 to electric utility margin in 2006, with no impact on operating income or net income. The change resulted from an analysis conducted in conjunction with the expiration and renegotiation of certain transmission agreements, resulting in better alignment of reporting for such costs consistent with Midwest Independent Transmission System Operator, Inc. (MISO) classification.

Short-term Wholesale and Commodity Trading Margins - Short-term wholesale margins consist of energy-related purchase and sales activity and the use of financial instruments associated with the fuel required for and energy produced from Xcel Energy’s generation assets and energy and capacity purchased to serve native load. Commodity trading margins are not associated with Xcel Energy’s generation assets or the capacity and energy purchased to serve native load.

As expected, short-term wholesale margins declined in 2006 due to retail sales growth, which reduced generation available for sale in the wholesale market, reductions in the availability of the coal-fired, King plant due to the MERP project, decreased opportunities to sell resulting from the MISO centralized dispatch market, and the Minnesota rate case settlement agreement to refund to customers the majority of short-term wholesale margins attributable to Minnesota jurisdiction customers starting in 2006.

Natural Gas Utility Margins — The following table details the changes in natural gas utility revenue and margin. The cost of natural gas tends to vary with changing sales requirements and the unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.

	Three Months Ended Dec. 31,						Twelve Months Ended Dec. 31,
(Millions of dollars)	2006			2005			2006			2005
Natural gas utility revenue	$	637		$	939		$	2,156		$	2,307
Cost of natural gas sold and transported	(489		)	(795		)	(1,645		)	(1,823		)
Natural gas utility margin	$	148		$	144		$	511		$	484

6

The following summarizes the components of the changes in natural gas margin for the three and 12 months ended Dec. 31:

	Three months ended Dec. 31,			Twelve months ended Dec. 31,
(Millions of dollars)	2006 vs. 2005			2006 vs. 2005
Base rate changes	$	9		$	32
Transportation	2			8
Sales decline - excluding weather impact	(5		)	(7		)
Estimated impact of weather	1			(4		)
Other	(3		)	(2		)
Total natural gas margin increase	$	4		$	27

Other Operating and Maintenance Expenses — Utility — Other operating and maintenance expenses for the fourth quarter of 2006 increased $16 million, or 3.5 percent, compared with the same period in 2005. The increase is primarily due to higher performance-based employee benefit costs for the quarter, and higher nuclear and combustion/hydro plant costs.

Partially offsetting the increase is the reclassification of transmission expense to electric margin previously discussed, which has no impact on net income, as well as the recognition of gains associated with the sale of certain assets, including the Oklahoma and Kansas delivery system operations of Southwestern Public Service Co. (SPS) and steel railcars of Public Service Co. of Colorado (PSCo). In conjunction with a regulatory decision, a $17 million regulatory asset was established associated with Private Fuel Storage costs.

Other operating and maintenance expenses for 2006 increased $64 million, or 3.8 percent, compared with 2005. Higher employee benefit costs, which are primarily performance-based, and higher nuclear and combustion/hydro plant costs were offset by lower nuclear plant outage costs, the transmission reclassification, gains on sale of assets, and the establishment of the Private Fuel Storage regulatory asset, mentioned above. For more information, see the following table:

	Three months ended Dec. 31,			Twelve months ended Dec. 31,
(Millions of Dollars)	2006 vs. 2005			2006 vs. 2005
Transmission fees classification change	$	(7	)	(26		)
Private Fuel Storage regulatory asset	(17		)	(17		)
Gains on sale or disposal of assets, net	(9		)	(9		)
Higher (lower) nuclear plant outage costs	17			(4		)
Higher employee benefit costs, primarily performance-based	19			38
Higher combustion/hydro plant costs	8			24
Higher nuclear plant operating costs	2			22
Higher uncollectible receivable costs	8			15
Higher consulting costs	2			8
Higher conservation incentive program costs	—			4
Other, including fleet transportation and facilities costsOther	(7		)	9
Total operating and maintenance expense increase	$	16		$	64

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $15 million, or 7.9 percent, for the fourth quarter, and $55 million, or 7.1 percent, for the 12 months of 2006, compared with the same periods in 2005. The decommissioning accruals increased by $20 million in 2006, reflecting regulatory recovery decisions. Normal plant additions accounted for the remaining increase in depreciation expense for 2006 over 2005.

7

Income Taxes — Income taxes for continuing operations decreased by $19 million for the fourth quarter of 2006, compared with 2005. The effective tax rate was 20.2 percent for the fourth quarter of 2006, compared with 30.4 percent for the same period in 2005. The decrease in income taxes and the effective tax rate was primarily due to a reduction in pretax income.

Income taxes for continuing operations increased by $8 million for 2006, compared with 2005. The effective tax rate for continuing operations was 24.2 percent for 2006, compared with 25.8 percent for 2005. The increase in income tax expense was primarily due to an increase in pretax income, partially offset by $30 million of tax benefits from the reversal of a regulatory reserve and realized capital loss carryforwards. Without these tax benefits, the effective tax rate for 2006 would have been 28.2 percent. In 2005, tax benefits of $10 million were recorded from increased research credits and a net operating loss carry back.

Note 3. Xcel Energy Capital Structure

The following is the capital structure of Xcel Energy at Dec. 31, 2006:

(Billions of Dollars)	Balance at Dec. 31, 2006		Percentage of Total Capitalization
Current portion of long-term debt	$	0.3	2	%
Short-term debt	0.6		5	%
Long-term debt	6.5		49	%
Total debt	7.4		56	%
Preferred equity	0.1		1	%
Common equity	5.7		43	%
Total equity	5.8		44	%
Total capitalization	$	13.2	100	%

Note 4. Rates and Regulation

Northern States Power Co., a Minnesota corporation, (NSP-Minnesota) Electric Rate Case — In 2006, NSP-Minnesota requested an electric rate increase in Minnesota of $156 million, based on a requested 11 percent return on common equity, a projected common equity to total capitalization ratio of 51.7 percent and a projected electric rate base of $3.2 billion.

On Sept. 1, 2006, the Minnesota Public Utilities Commission (MPUC) issued a written order granting an electric revenue increase of approximately $131 million for 2006 based on an authorized return on equity of 10.54 percent. In 2007, the rate increase will be reduced to $115 million to reflect the return of Flint Hills Resources, a large industrial customer, to the NSP-Minnesota system.

In November 2006, the MPUC declined to act on petitions for reconsideration, which allows the Sept. 1, 2006, order to stand. A customer intervenor has filed a petition for review of the MPUC decision with the Minnesota Court of Appeals.

NSP-Minnesota Natural Gas Rate Case — In November 2006, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $18.5 million, which represents an increase of 2.4 percent. The request is based on 11.0 percent return on equity, a projected equity ratio of 51.98 percent and a natural gas rate base of $439 million. Interim rates, subject to refund, were set at a $15.9 million increase and went into effect on Jan. 8, 2007. A decision is expected in the summer of 2007.

PSCo Electric Rate Case — In 2006, PSCo filed with the Colorado Public Utilities Commission (CPUC) to increase electricity rates by $208 million annually, beginning Jan. 1, 2007. The request was based on a return on equity of 11 percent, an equity ratio of 59.9 percent and an electric rate base of $3.4 billion. No interim rate increase was implemented.

8

On Nov. 20, 2006, the CPUC approved a settlement agreement, which authorized an overall rate increase of $151 million, effective Jan. 1, 2007, including:

·A $107 million base rate increase based on a 10.50 percent return on equity and 60 percent equity ratio.

·A purchased capacity cost adjustment (PCCA) rider for all capacity costs associated with new purchased power agreements that will increase 2007 revenues by $39.4 million.

·$4.6 million increase in Windsource-related costs recovered through the electric cost adjustment.

PSCO Natural Gas Rate Case — On Dec. 1, 2006, PSCo filed with the CPUC a request to increase natural gas rates by $41.5 million, representing an overall increase of 2.96 percent. The request is based on a requested capital structure of 60.17 percent common equity, a return on common equity of 11 percent and a rate base of approximately $1.1 billion. It is anticipated that new rates will become effective in the third quarter of 2007.

SPS-Texas Electric Rate Case — On May 31, 2006, SPS filed a Texas retail electric rate case requesting an increase in annual revenues of approximately $48 million, or 6.0 percent. The rate filing is based on a historical test year, an electric rate base of $943 million, a requested return on equity of 11.6 percent and a common equity ratio of 51.1 percent.

On Sept. 25, 2006, SPS filed corrections to its rate case revenue requirements calculations, increasing the revenue requirements an additional $15 million, to approximately $63 million. As a result of not re-filing the entire case for these corrections, SPS will be limited to a maximum increase of $48 million, the increase originally requested. No interim rate increase has been implemented.

In addition, SPS has a pending fuel reconciliation filing, which seeks approval of approximately $957 million of Texas jurisdictional fuel and purchased power costs for 2004 through 2005. The fuel reconciliation case was transferred to the State Office of Administrative Hearing (SOAH) with the base rate case and has the same procedural schedule. As a part of the fuel reconciliation case, fuel and purchased energy costs, which are recovered in Texas through a fixed-fuel and purchased energy recovery factor as a part of SPS’ retail electric rates, will be reviewed.

Various parties have filed testimony on base rate and fuel issues, including the Office of Public Utility Counsel; the state of Texas; Texas Industrial Electric Consumers; Association of Xcel Municipalities; Occidental Permian; and the Public Utility Commission of Texas Staff. Intervenor recommendations ranged from a base rate reduction of $56 million to a base rate increase of $31 million.

In the fuel reconciliation portion of the proceeding, the parties recommended several adjustments related to SPS’s fuel reconciliation filing, including the methodology for assigning average fuel costs to certain firm wholesale sales, coal mitigation activities, the treatment of fuel losses and other items. The recommendation ranged from a disallowance of $8 million to a disallowance of $120 million.

SPS’ rebuttal testimony was filed in January, 2007. SPS is confident that the rebuttal case adequately addressed many of the concerns raised by intervenors. Final rates are expected to be effective in the second quarter of 2007. No interim rate increase has been implemented.

SPS has recorded a reserve for various regulatory issues, including the electric rate case and the fuel reconciliations.

Note 5. Capital and Equity Investments

Sherco Upgrade — On Jan. 2, 2007, NSP-Minnesota proposed an emissions reduction project at its Sherco plant in Becker, Minn., in connection with a plan to increase generating capacity at the station to meet customers’ growing needs. The proposal would add a total of 140 megawatts of capacity for NSP-Minnesota’s customers and take a major step toward extending the plant’s life while significantly reducing emissions of mercury, nitrogen oxides,

9

sulfur dioxide and particulates. A portion of the proposal requires approval by Southern Minnesota Municipal Power Agency, which owns part of Sherco Unit 3.

By Sept. 1, 2007, NSP-Minnesota plans to file a petition seeking rate rider recovery for the project, which preliminary estimates indicate would cost approximately $900 million. Stakeholders will have the opportunity to comment on the proposal, and the MPUC is expected to rule on the proposal in 2008. If approved, NSP-Minnesota plans to begin construction on the project in late 2008 and complete work by 2012.

Wind Generation — NSP-Minnesota is considering investing $210 million in 2009 to acquire 100-megawatts of wind generation under a build-own-transfer structure. The project would be eligible for rider recovery in Minnesota. The project requires approval by the MPUC.

WYCO Development LLC (WYCO) Equity Investment — Xcel Energy holds a 50 percent interest in WYCO. In 1999, WYCO was jointly formed with a subsidiary of El Paso Corporation to develop and lease new natural gas pipeline and compression facilities. WYCO now proposes to develop additional new natural gas transportation and storage facilities in support of the natural gas delivery systems used by PSCo. Xcel Energy plans to invest approximately $145 million in WYCO between 2007 and 2009. The investment will be used to build 164 miles of natural gas transmission pipeline and natural gas storage facilities in Colorado having working gas capacity of approximately 7 billion cubic feet. The WYCO pipeline project is expected to begin operations in 2008, and the WYCO storage project is expected to begin operations in 2009. The facilities will be regulated by the FERC and leased and operated by Colorado Interstate Gas Company, an affiliate of El Paso Corporation.

Note 6. Xcel Energy Earnings Guidance

2007 Earnings Guidance — Xcel Energy’s 2007 earnings per share from continuing operations guidance and key assumptions are detailed in the following table.

	2007 Diluted EPS Range
Utility operations		$	1.39 – $1.49
Corporate-owned life insurance (COLI) tax benefit		$0.11
Holding company financing costs and other		$(0.15)
Xcel Energy Continuing Operations — EPS		$	1.35 – $1.45

Key Assumptions for 2007:

·Normal weather patterns are experienced during the year;

·Reasonable rate recovery is approved in the SPS Texas electric rate case;

·No material incremental accruals related to the SPS regulatory proceedings;

·Reasonable rate recovery in the Minnesota and Colorado natural gas rate cases;

·Weather-adjusted retail electric utility sales grow by approximately 1.7 percent to 2.2 percent;

·Weather-adjusted retail natural gas utility sales decline by approximately 1.0 percent to 2.0 percent;

·Short-term wholesale and commodity trading margins are within a range of $15 million to $25 million;

·Capacity costs at NSP-Minnesota and SPS are projected to increase approximately $35 million. Capacity costs at PSCo are expected to be recovered under the PCCA;

·Utility operating and maintenance expenses increase between 2 percent and 3 percent;

·Depreciation expense increases approximately $45 million to $55 million;

·Interest expense increases approximately $30 million to $35 million;

·Allowance for funds used during construction-equity increases approximately $17 million to $23 million;

·Xcel Energy continues to recognize COLI tax benefits, which is currently being litigated with the Internal Revenue Service;

·The effective tax rate for continuing operations is approximately 28 percent to 31 percent; and

·Average common stock and equivalents total approximately 433 million shares, based on the “If Converted” method for convertible notes.

10

XCEL ENERGY INC. AND SUBSIDIARIES

UNAUDITED EARNINGS RELEASE SUMMARY

All dollars in thousands, except earnings per share

	Three months ended Dec. 31,
	2006			2005
Operating revenue:
Electric and natural gas utility revenue, and trading margins	$	2,452,307		$	2,861,126
Nonregulated and other revenue	14,429			21,111
Total revenue	$	2,466,736		$	2,882,237
Income from continuing operations	$	96,758		$	98,964
Income from discontinued operations	960			13,104
Net income	$	97,718		$	112,068
Earnings available for common shareholders	$	96,658		$	111,008
Average shares — common and potentially dilutive (1000’s)	431,156			426,570
Segments and Components of Earnings per share — diluted
Utility earnings — continuing operations	$	0.27		$	0.27
Losses from nonregulated subsidiaries and holding company	(0.04		)	(0.03		)
Earnings per share — continuing operations	0.23			0.24
Discontinued operations	—			0.03
Total earnings per share — GAAP	$	0.23		$	0.27

	Twelve months ended Dec. 31,
	2006			2005
Operating revenue:
Electric and natural gas utility revenue, and trading margins	$	9,764,017		$	9,551,022
Nonregulated and other revenue	76,287			74,455
Total revenue	$	9,840,304		$	9,625,477
Income from continuing operations	$	568,681		$	499,038
Income from discontinued operations	3,073			13,934
Net income	$	571,754		$	512,972
Earnings available for common shareholders	$	567,513		$	508,731
Average shares — common and potentially dilutive (1000’s)	429,605			425,671
Segments and Components of Earnings per share — diluted
Utility earnings — continuing operations	$	1.41		$	1.27
Losses from nonregulated subsidiaries and holding company	(0.06		)	(0.07		)
Earnings per share — continuing operations	1.35			1.20
Discontinued operations	0.01			0.03
Total earnings per share — GAAP	$	1.36		$	1.23
Book value per share	$	14.05		$	13.42

11