Exhibit 99.01

	414 Nicollet Mall
	Minneapolis, MN 55401

Jan. 28, 2010

XCEL ENERGY

2009 YEAR END EARNINGS REPORT

· Ongoing earnings per diluted share were $1.50 in 2009, compared with $1.45 per diluted share in 2008.

· 2009 ongoing earnings of $1.50 per share achieve the mid-point of Xcel Energy’s guidance range.

· GAAP (generally accepted accounting principles) earnings were $681 million, or $1.48 per diluted share in 2009, compared with $646 million, or $1.46 per diluted share in 2008.

· Xcel Energy reaffirms its 2010 earnings guidance of $1.55 to $1.65 per diluted share.

MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) today reported 2009 GAAP earnings of $681 million or $1.48 per diluted share, compared with 2008 GAAP earnings of $646 million, or $1.46 per diluted share. Ongoing earnings, adjusted for certain non-recurring items, were $1.50 per diluted share in 2009, compared with $1.45 per diluted share in 2008.

Higher 2009 ongoing earnings were primarily due to improved electric margins as a result of constructive rate case outcomes in Minnesota, Colorado, Texas, New Mexico and Wisconsin, which were partially mitigated by the negative impact of weather, lower sales and higher purchase capacity power costs. Offsetting stronger electric margins were higher operating and maintenance expenses, resulting from increased employee benefit costs as well as higher nuclear expenses, and dilution from the issuance of equity to fund the capital investment program.

“Overall, 2009 was a successful year,” said Richard C. Kelly, chairman and chief executive officer. “We delivered earnings within our guidance range for the fifth straight year, despite the difficult economy and cool summer weather, which reduced sales. On the operational front, we saw improved customer satisfaction and system reliability as well as the completion of major construction projects at Riverside and Fort St. Vrain. We made significant progress in the construction of the Comanche Unit 3, which is now expected to go into service in February 2010. Finally, we concluded seven rate cases, across our service regions, with constructive outcomes. In addition, we are reaffirming our 2010 earnings guidance of $1.55 to $1.65 per share.”

Earnings Adjusted for Certain Non-recurring Items (Ongoing Earnings)

The following table provides a reconciliation of ongoing earnings per share to GAAP earnings per share for 2009 and 2008:

	Three Months Ended Dec. 31,				Twelve Months Ended Dec. 31,
Diluted earnings (loss) per share	2009		2008		2009			2008
Ongoing(a) diluted earnings per share	$	0.37	$	0.35	$	1.50		$	1.45
PSRI	—		0.01		(0.01		)	0.01
Earnings per share from continuing operations	0.37		0.36		1.49			1.46
Loss per share from discontinued operations	—		—		(0.01		)	—
GAAP diluted earnings per share	$	0.37	$	0.36	$	1.48		$	1.46

(a) See Note 6.

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,
	2009			2008			2009			2008
Operating revenues
Electric	$	1,953,810		$	1,978,829		$	7,703,017		$	8,682,993
Natural gas	641,542			706,287			1,865,703			2,442,988
Other	21,058			22,457			73,877			77,175
Total operating revenues	2,616,410			2,707,573			9,642,597			11,203,156

Operating expenses
Electric fuel and purchased power	966,832			1,076,542			3,670,784			4,947,979
Cost of natural gas sold and transported	456,649			533,968			1,266,440			1,832,699
Cost of sales — other	7,839			6,987			22,107			21,082
Other operating and maintenance expenses	497,337			437,571			1,908,097			1,777,933
Conservation and demand side management program expenses	48,319			25,435			182,112			117,713
Depreciation and amortization	208,767			205,867			818,052			828,379
Taxes (other than income taxes)	77,409			68,360			306,433			286,580
Total operating expenses	2,263,152			2,354,730			8,174,025			9,812,365

Operating income	353,258			352,843			1,468,572			1,390,791

Other income, net	5,376			13,135			9,771			40,406
Equity earnings of unconsolidated subsidiaries	13,904			1,736			24,664			3,571
Allowance for funds used during construction — equity	20,121			18,041			75,686			63,519

Interest charges and financing costs
Interest charges — includes other financing costs of $4,907, $5,096, $20,162 and $20,390, respectively	141,207			147,248			561,654			552,919
Allowance for funds used during construction — debt	(10,128		)	(10,290		)	(39,799		)	(39,038		)
Total interest charges and financing costs	131,079			136,958			521,855			513,881

Income from continuing operations before income taxes	261,580			248,797			1,056,838			984,406
Income taxes	90,733			85,240			371,314			338,686
Income from continuing operations	170,847			163,557			685,524			645,720
Income (loss) from discontinued operations, net of tax	(1,964		)	518			(4,637		)	(166		)
Net income	168,883			164,075			680,887			645,554
Dividend requirements on preferred stock	1,060			1,060			4,241			4,241
Earnings available to common shareholders	$	167,823		$	163,015		$	676,646		$	641,313

Weighted average common shares outstanding:
Basic	457,434			451,748			456,433			437,054
Diluted	458,357			455,174			457,139			441,813
Earnings per average common share — basic
Earnings from continuing operations	$	0.37		$	0.36		$	1.49		$	1.47
Loss from discontinued operations	—			—			(0.01		)	—
Earnings per share	$	0.37		$	0.36		$	1.48		$	1.47
Earnings per average common share — diluted
Earnings from continuing operations	$	0.37		$	0.36		$	1.49		$	1.46
Loss from discontinued operations	—			—			(0.01		)	—
Earnings per share	$	0.37		$	0.36		$	1.48		$	1.46

Cash dividends declared per common share	$	0.24		$	0.24		$	0.97		$	0.94

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.

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	2009			2008			2009			2008
Public Service Company of Colorado (PSCo)	$	0.21		$	0.19		$	0.72		$	0.76
NSP-Minnesota	0.16			0.14			0.64			0.65
NSP-Wisconsin	0.02			0.03			0.10			0.10
Southwestern Public Service Company (SPS)	0.01			0.01			0.15			0.07
Equity earnings of unconsolidated subsidiaries	0.01			0.01			0.03			0.01
Regulated utility — continuing operations (Note 2)	0.41			0.38			1.64			1.59
Holding company and other costs	(0.04		)	(0.03		)	(0.14		)	(0.14		)
Ongoing(a) diluted earnings per share	0.37			0.35			1.50			1.45
PSRI	—			0.01			(0.01		)	0.01
Earnings per share from continuing operations	0.37			0.36			1.49			1.46
Loss per share from discontinued operations	—			—			(0.01		)	—
GAAP diluted earnings per share	$	0.37		$	0.36		$	1.48		$	1.46

(a) See Note 6.

PSCo — Earnings at PSCo increased by two cents per share for the fourth quarter and decreased by four cents per share for 2009. The 2009 decrease is largely due to the negative impact of weather and rising costs, partially offset by new electric rates that went into effect in July 2009.

NSP-Minnesota — Earnings at NSP-Minnesota increased by two cents per share for the fourth quarter and decreased by one cent per share for 2009. The 2009 decrease is mainly due to the negative impact of weather and timing of nuclear outage expenses. The decrease was partially mitigated by a $91 million electric rate increase that went into effect in January 2009.

NSP-Wisconsin — Earnings at NSP-Wisconsin decreased by one cent per share for the fourth quarter and were flat for 2009. The 2009 earnings reflect increased costs, which were offset by improved fuel recovery and new rates which were effective in January 2009.

SPS — Earnings at SPS were flat for the fourth quarter and increased by eight cents per share for 2009. The 2009 increase was primarily due to electric rate increases in Texas (effective in February 2009) and New Mexico (effective in July 2009) and the 2008 resolution of certain fuel cost allocation issues, which were partially offset by higher purchased capacity costs.

Equity Earnings of Unconsolidated Subsidiaries — Equity earnings of unconsolidated subsidiaries were flat for the fourth quarter and increased by two cents per share for 2009, due to our investment in WYCO, which owns a natural gas pipeline in Colorado that began operations in late 2008 as well as a gas storage facility that commenced operations in July 2009.

PSRI —PSRI is a wholly owned subsidiary of PSCo. During 2007, Xcel Energy resolved a dispute with the IRS regarding its Corporate Owned Life Insurance (COLI) program. The 2009 impact is primarily related to legal costs associated with company claims against the insurance provider and broker of the COLI policies.

Discontinued Operations — Loss from discontinued operations increased by one cent over 2008 primarily due to an increase in tax related expenses and legal accruals for previously divested businesses.

The following table summarizes significant components contributing to the changes in the 2009 diluted earnings per share compared with the same periods in 2008, which are discussed in more detail later in the release.

	Three Months			Twelve Months
	Ended Dec. 31,			Ended Dec. 31,
2008 GAAP diluted earnings per share	$	0.36		$	1.46
PSRI	(0.01		)	(0.01		)
2008 ongoing(a) diluted earnings per share	0.35			1.45

Components of change — 2009 vs. 2008
Higher electric margins	0.12			0.44
Higher (lower) natural gas margins	0.02			(0.02		)
Higher equity earnings of unconsolidated subsidiaries	—			0.02
Higher operating and maintenance expenses	(0.09		)	(0.19		)
Higher conservation and DSM expenses (generally offset in revenues)	(0.03		)	(0.09		)
Lower other income (expense), net	(0.01		)	(0.05		)
Higher taxes, other than income taxes	(0.01		)	(0.03		)
Dilution from DRIP, benefit plans and the 2008 common equity issuance	—			(0.05		)
Other, net, including AFUDC, depreciation and higher effective tax rate	0.02			—
2009 GAAP diluted earnings per share	0.37			1.48
Loss per share from discontinued operations	—			0.01
Earnings per share from continuing operations	0.37			1.49
PSRI	—			0.01
2009 ongoing(a) diluted earnings per share	$	0.37		$	1.50

(a)	See Note 6.

Note 2. Regulated Utility Results — Continuing Operations

Estimated Impact of Temperature Changes on Regulated Earnings — 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,
	2009 vs.		2008 vs.		2009 vs.		2009 vs.			2008 vs.			2009 vs.
	Normal		Normal		2008		Normal			Normal			2008
Retail electric	$	—	$	—	$	—	$	(0.05	)	$	(0.01	)	$	(0.04	)
Firm natural gas	0.01		—		0.01		—			0.01			(0.01		)
Total	$	0.01	$	—	$	0.01	$	(0.05	)	$	—		$	(0.05	)

Sales — The following table summarizes changes in Xcel Energy’s sales for actual and weather-normalized sales for 2009 as compared with the same periods in 2008, excluding the impact of the 2008 leap year.

	Three Months Ended Dec. 31,				Twelve Months Ended Dec. 31,
	Actual		Normalized		Actual		Normalized
Electric residential	1.5	%	1.2	%	(1.4	)%	0.7	%
Electric commercial and industrial	(3.2	)	(3.2	)	(3.3	)	(2.7	)
Total retail electric sales	(1.9	)	(2.0	)	(2.7	)	(1.8	)
Firm natural gas sales	5.9		1.0		(2.6	)	0.8

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 fuel recovery mechanisms these price fluctuations have little impact on electric margin. The following tables detail the electric revenues and margin:

	Three Months Ended Dec. 31,						Twelve Months Ended Dec. 31,
(Millions of Dollars)	2009			2008			2009			2008
Electric revenues	$	1,954		$	1,979		$	7,703		$	8,683
Electric fuel and purchased power	(967		)	(1,077		)	(3,671		)	(4,948		)
Electric margin	$	987		$	902		$	4,032		$	3,735

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

	Three Months			Twelve Months
	Ended Dec. 31,			Ended Dec. 31,
(Millions of Dollars)	2009 vs. 2008			2009 vs. 2008
Retail rate increases (Colorado, Minnesota, Texas, New Mexico and Wisconsin)	$	59		$	218
Conservation and DSM revenue and incentive (partially offset by expenses)	22			74
Metropolitan Emissions Reduction Project (MERP) rider	4			17
NSP-Wisconsin fuel recovery	4			14
Non-fuel riders	3			22
Firm wholesale	1			11
2008 refund of nuclear refueling outage revenues due to change in recovery method	1			16
Sales mix and demand revenues	(8		)	4
Retail sales decline (excluding weather impact)	(5		)	(22		)
Estimated impact of weather	(2		)	(26		)
Purchased capacity costs	—			(44		)
SPS 2008 fuel cost allocation regulatory accruals	—			12
Other, net	6			1
Total increase in electric margin	$	85		$	297

Xcel Energy experienced a decline in megawatt hours (MwH) sales, which we believe was driven by overall economic conditions and to a lesser degree, increased conservation efforts. The declines in MwH sales to the commercial and industrial customer class, which are directly related to the economic downturn, are partially offset by demand charges, which mitigate, to a certain degree, the impact of the lower MwH sales.

Natural Gas — The cost of natural gas tends to vary with changing sales requirements and the 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. The following tables detail natural gas revenues and margin:

	Three Months Ended Dec. 31,						Twelve Months Ended Dec. 31,
(Millions of Dollars)	2009			2008			2009			2008
Natural gas revenues	$	642		$	706		$	1,866		$	2,443
Cost of natural gas sold and transported	(457		)	(534		)	(1,266		)	(1,833		)
Natural gas margin	$	185		$	172		$	600		$	610

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

	Three Months		Twelve Months
	Ended Dec. 31,		Ended Dec. 31,
(Millions of Dollars)	2009 vs. 2008		2009 vs. 2008
Estimated impact of weather	$	3	$	(10	)
Conservation and DSM revenue and incentive (partially offset by expenses)	3		6
Other (including sales mix), net	7		(6		)
Total increase (decrease) in natural gas margin	$	13	$	(10	)

Other Operating and Maintenance (O&M) Expenses — Other O&M expenses increased by approximately $59.8 million, or 13.7 percent, for the fourth quarter and approximately $130.2 million, or 7.3 percent for 2009. The following table summarizes the changes in other O&M expenses:

	Three Months			Twelve Months
	Ended Dec. 31,			Ended Dec. 31,
(Millions of Dollars)	2009 vs. 2008			2009 vs. 2008
Higher employee benefit costs	$	50		$	90
Nuclear outage costs, net of deferral	5			30
Higher plant generation costs	4			9
Higher information technology costs	4			6
Higher labor costs	3			6
Higher insurance costs	3			7
Higher (lower) material costs	3			(4		)
Higher (lower) consulting costs	1			(18		)
Lower uncollectible receivable costs	(12		)	(14		)
Higher nuclear plant operation costs	—			21
Other, net	(1		)	(3		)
Total increase in other operating and maintenance expenses	$	60		$	130

· Higher employee benefits costs are primarily attributable to 2009 employee performance based incentive compensation expenses, higher pension expenses and increased medical expenses. In 2008, no employee performance based incentive benefits were earned.

· The increase in nuclear outage costs is due to the commissions’ approval of the change in the nuclear refueling outage recovery method from the direct expense method to the deferral and amortization method in 2008.

· The increase in nuclear plant operation costs is driven primarily by an increase in security costs and regulatory fees, resulting from new Nuclear Regulatory Commission requirements.

· Lower consulting costs are primarily the result of cost management initiatives achieved throughout 2009.

· Lower uncollectible receivable costs are mainly due to improved collections and a decrease in natural gas prices.

Conservation and Demand Side Management (DSM) Program Expenses — Conservation and DSM program expenses increased approximately $22.9 million and $64.4 million for the three and twelve months ended 2009, respectively. The higher expense was attributable to the expansion of programs and regulatory commitments. Conservation and DSM program expenses are recovered through riders or base rates.

Depreciation and Amortization — Depreciation and amortization expenses increased by approximately $2.9 million, or 1.4 percent, for the fourth quarter of 2009, and decreased by $10.3 million, or 1.2 percent, for 2009. In 2009, NSP-Minnesota began recognizing a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation, as a result of the Minnesota Public Utilities Commission (MPUC) decision in the Minnesota electric rate case. In addition, in 2009, the MPUC extended the recovery period of decommissioning expense by 10 years for the Prairie Island and the Monticello nuclear plants. These decisions reduced depreciation and decommissioning expense in 2009. These decreases were partially offset by normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $9.0 million, or 13.2 percent, for the fourth quarter of 2009, and by $19.9 million, or 6.9 percent, for 2009, compared with the same periods in 2008. The increase was primarily due to increased property taxes across our jurisdictions.

Other Income, Net — Other income net decreased by approximately $7.8 million during the fourth quarter of 2009 and by $30.6 million for 2009, compared with the same periods in 2008. The net decline was mainly due to changes in our non-qualified benefit plan liabilities related to market activity, lower interest on under recovered deferred fuel balances and a decrease in interest received from WYCO for construction deposits.

Equity Earnings of Unconsolidated Subsidiaries — Equity earnings of unconsolidated subsidiaries increased by $12.2 million for the fourth quarter of 2009, and by $21.1 million for 2009, compared with the same periods in 2008. The increase was primarily due to higher earnings from the equity investment in WYCO as a result of the High Plains natural gas pipeline, located in Colorado, which commenced operations in late 2008 as well as a storage facility that began operations in July 2009.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased by approximately $1.9 million, or 6.8 percent, for the fourth quarter of 2009, and by $12.9 million, or 12.6 percent, for 2009, compared with the same periods in 2008. The increase was due primarily to the construction of Comanche Unit 3, a power facility located in Colorado, as well as other construction projects.

Interest Charges — Interest charges decreased by approximately $6.0 million, or 4.1 percent, for the fourth quarter of 2009 and increased by $8.7 million, or 1.6 percent, for 2009, compared with the same periods in 2008. The lower interest expense in the fourth quarter was largely due to lower interest rates on long and short-term debt. The year-to-date increase was primarily the result of increased debt levels to fund new capital investments partially offset by lower interest rates on short-term debt.

Income Taxes — Income tax expense for continuing operations increased by $5.5 million for the fourth quarter of 2009, compared with 2008. The increase in income tax expense was primarily due to an increase in pretax income. The effective tax rate for continuing operations was 34.7 percent for the fourth quarter of 2009, compared with 34.3 percent for the same period in 2008.

Income tax expense for continuing operations increased by $32.6 million for the twelve months ending Dec. 31, 2009, compared with the same period in 2008. The increase in income tax expense was primarily due to an increase in pretax income in 2009. The effective tax rate for continuing operations was 35.1 percent for 2009, compared with 34.4 percent for 2008. The higher effective tax rate for 2009 was primarily due to the establishment of a valuation allowance against certain state tax credit carryovers that are now expected to expire prior to full utilization. Excluding this item, the effective tax rate for 2009 would have been 34.6 percent.

Note 3. Xcel Energy Capital Structure and Financing

Following is the capital structure of Xcel Energy at Dec. 31, 2009:

			Percentage
	Balance at		of Total
(Billions of Dollars)	Dec. 31, 2009		Capitalization
Current portion of long-term debt	$	0.5	3	%
Short-term debt	0.5		3
Long-term debt	7.9		49
Total debt	8.9		55
Preferred equity	0.1		—
Common equity	7.3		45
Total equity	7.4		45
Total capitalization	$	16.3	100	%

Financing Plans — Xcel Energy issues debt securities to refinance retiring maturities, reduce short-term debt, fund construction programs and for other general corporate purposes. Xcel Energy plans to issue the following debt securities in 2010:

· Up to $500 million of unsecured debt at the holding company, and

· Up to $500 million of first mortgage bonds at NSP-Minnesota

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

Xcel Energy and Utility Subsidiary Credit Facilities — As of Jan. 20, 2010, Xcel Energy had the following credit facilities available to meet its liquidity needs:

(Millions of Dollars)	Facility		Drawn(a)		Available		Cash		Liquidity		Maturity
NSP-Minnesota	$	482.2	$	23.8	$	458.4	$	0.7	$	459.1	December 2011
PSCo	675.1		64.6		610.5		0.7		611.2		December 2011
SPS	247.9		10.0		237.9		1.3		239.2		December 2011
Xcel Energy – Holding Company	771.6		380.6		391.0		3.9		394.9		December 2011
NSP-Wisconsin(b)	—		—		—		5.2		5.2
Total	$	2,176.8	$	479.0	$	1,697.8	$	11.8	$	1,709.6

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

(b) NSP-Wisconsin does not have a separate credit facility; however, it has a short-term borrowing agreement with NSP-Minnesota.

Note 4. Rates and Regulation

NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota gas rates by $16.2 million for 2010, which represents a 2.8 percent overall increase in customer bills. This request is based on a return on equity (ROE) of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million. NSP-Minnesota also requested an additional increase of $3.45 million for recovery of pension funding costs effective Jan. 1, 2011. Interim rates of $11.1 million went into effect on Jan. 11, 2010, subject to refund. An MPUC decision is expected in late 2010.

PSCO- Wholesale Rate Case — In 2009, PSCo filed to increase Colorado wholesale rates by $30 million based on a 12.5 percent ROE, a 58 percent equity ratio and an electric production rate base of $315 million. PSCo has requested that FERC suspend action on the filing to allow time for settlement negotiations. Settlement discussions with our wholesale customers are continuing. PSCo expects final rates will go into effect later in 2010.

NSP-Minnesota - South Dakota Electric Rate Case — In June 2009, NSP-Minnesota filed to increase South Dakota electric rates by $18.6 million, or 12.7 percent. The request was based on a requested ROE of 11.25 percent, an electric rate base of $282 million, an equity ratio of 51.63 percent and a 2008 historic test year, adjusted for known and measurable changes in rate base and O&M expense.

On Jan. 5, 2010, the South Dakota Commission approved a settlement agreement, which increases electric base rates by $10.9 million. The primary difference between the approved rate increase and requested amount was due to a lower ROE and the use of a 20-year life for the Prairie Island nuclear plant, which reduced the revenue deficiency and expense accruals by a corresponding amount. New rates were effective on Jan. 18, 2010.

NSP-Wisconsin - Electric and Gas Rate Case — In June 2009, NSP-Wisconsin filed an electric and gas rate case in Wisconsin seeking an increase in retail electric rates of $30.4 million, or 5.7 percent, and proposed no change in natural gas rates. The request was based on an ROE of 10.75 percent, an equity ratio of 53.12 percent, an electric rate base of $644 million, a gas rate base of $81 million and a 2010 forecasted test year. The request was comprised of a base rate increase of $45.1 million offset by projected fuel decreases of $14.7 million.

In December 2009, the Public Service Commission of Wisconsin approved an electric rate increase of approximately $6.4 million and no change in gas rates, based on a 10.4 percent ROE and a 52.3 percent equity ratio. The major differences between the request and the authorized increase include lower depreciation and decommission expense related to the life extension of the Prairie Island nuclear plant, reductions to forecast fuel costs, a lower ROE, a lower equity ratio and adjustments to interchange fixed charges and O&M expenses. New rates were effective January 2010.

PSCo - 2010 Electric Rate Case — In May 2009, PSCo filed a request with the Colorado Public Utility Commission (CPUC) to increase Colorado electric rates by $180.2 million, or 6.8 percent, effective in 2010. The request was based on a 2010 forecast test year, an 11.25 percent ROE, a rate base of $4.4 billion and an equity ratio of 58.05 percent. In October 2009, PSCo filed rebuttal testimony and revised the requested rate increase to $177.4 million.

In November 2009, PSCo reached a settlement agreement with certain intervenors. The settlement included an electric rate increase of approximately $136 million, effective Jan. 1, 2010. The settlement was based on a 10.5 percent ROE and reflects PSCo’s actual capital structure. The settlement was based on an historic test year, adjusted for 2010 known and measurable changes related to plant investment as well as certain operating costs.

In December 2009, the CPUC approved a rate increase of approximately $128.3 million. The difference between the settlement rate increase and the approved amount was primarily related to adjustments related to rate base for non-major projects and an adjustment to interest on long-term debt.

In December 2009, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo’s proposal to phase in the approved electric rate increase to reflect the actual cost of service. This decision is not expected to have a material impact on PSCo or Xcel Energy’s financial results. Under the plan the following increases will be implemented:

· A rate increase of $67 million was implemented on Jan. 1, 2010. The adjustments to the rate increase, as a result of the delay of the in-service date of Comanche Unit 3, include reduced O&M, property taxes, the impact of a delay in changes to jurisdictional allocators and depreciation expenses.

· Base rates will increase to $121 million, once Comanche Unit 3 goes into service (currently expected in February 2010).

· Finally, base rates will increase to $128.3 million on Jan.1, 2011 to reflect 2011 property taxes.

Several parties, including the Office of Consumer Counsel, have filed motions for reconsideration, which are pending before the CPUC.

Note 5. Xcel Energy Ongoing Earnings Guidance

Xcel Energy’s 2010 ongoing earnings guidance is $1.55 to $1.65 per share. Key assumptions are detailed below:

· Normal weather patterns are experienced for the year.

· Weather-adjusted retail electric utility sales grow approximately 1 percent.

· Weather-adjusted retail firm natural gas sales decline approximately 1 percent to 2 percent.

· Reflects increased revenue due to the full year impact of 2009 electric rate cases in Colorado, Texas and New Mexico, along with the 2010 electric rate increase in Colorado.

· Constructive outcomes in the Minnesota natural gas rate case and PSCo wholesale electric rate case.

· Increased rider revenue recovery of approximately $30 million.

· O&M expenses are projected to increase $115 million to $135 million, or 6 percent to 7 percent.

· Depreciation expense is projected to increase by $40 million to $50 million.

· Interest expense is projected to increase approximately $15 million to $25 million.

· AFUDC-equity is projected to decrease $25 million to $30 million.

· The effective tax rate for continuing operations is approximately 34 percent to 36 percent.

· Average common stock and equivalents total approximately 460 million shares.

Note 6. Non-GAAP Reconciliation

Ongoing earnings exclude the impact related to the COLI program. COLI policies were owned and managed by PSRI, a wholly owned subsidiary of PSCo. During 2007, Xcel Energy resolved a dispute with the IRS regarding its COLI program. The 2009 and 2008 earnings were not materially affected by the termination of the COLI program and the 2009 impact is primarily related to legal costs associated with company claims against the insurance provider and broker of the COLI policies.

As a result of the termination of the COLI program, Xcel Energy’s management believes that ongoing earnings provide a more meaningful comparison of earnings results between different periods in which the COLI program was in place and is more 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)	2009			2008		2009			2008
Ongoing earnings	$	173,058		$	158,586	$	690,031		$	641,122
PSRI	(2,211		)	4,971		(4,507		)	4,598
Total continuing operations	170,847			163,557		685,524			645,720
Income (loss) from discontinued operations	(1,964		)	518		(4,637		)	(166		)
GAAP earnings	$	168,883		$	164,075	$	680,887		$	645,554

XCEL ENERGY INC. AND SUBSIDIARIES

UNAUDITED EARNINGS RELEASE SUMMARY

(amounts in thousands, except earnings per share)

Three Months Ended Dec. 31,	2009			2008
Operating revenues:
Electric and natural gas revenues	$	2,595,352		$	2,685,116
Other	21,058			22,457
Total operating revenues	2,616,410			2,707,573

Income from continuing operations	170,847			163,557
Income (loss) from discontinued operations	(1,964		)	518
Net income	168,883			164,075

Earnings available to common shareholders	167,823			163,015
Weighted average diluted common shares outstanding	458,357			455,174

Components of Earnings per Share — Diluted
Regulated utility — continuing operations	0.41			0.38
Holding Company and other costs	(0.04		)	(0.03		)
Ongoing(a) diluted earnings per share	0.37			0.35
PSRI	—			0.01
Earnings per share from continuing operations	0.37			0.36
Loss per share from discontinued operations	—			—
GAAP diluted earnings per share	$	0.37		$	0.36

Twelve Months Ended Dec. 31,	2009			2008
Operating revenues:
Electric and natural gas revenues	$	9,568,720		$	11,125,981
Other	73,877			77,175
Total operating revenues	9,642,597			11,203,156

Income from continuing operations	685,524			645,720
Loss from discontinued operations	(4,637		)	(166		)
Net income	680,887			645,554

Earnings available to common shareholders	676,646			641,313
Weighted average diluted common shares outstanding	457,139			441,813

Components of Earnings per Share — Diluted
Regulated utility — continuing operations	1.64			1.59
Holding Company and other costs	(0.14		)	(0.14		)
Ongoing(a) diluted earnings per share	1.50			1.45
PSRI	(0.01		)	0.01
Earnings per share from continuing operations	1.49			1.46
Loss per share from discontinued operations	(0.01		)	—
GAAP diluted earnings per share	$	1.48		$	1.46

Book value per share	$	15.92		$	15.35

(a) See Note 6.

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Paul Johnson, Managing Director, Investor Relations and Assistant Treasurer	(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