XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(amounts in thousands, except per share data)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2009			2008			2009			2008
Operating revenues
Electric	$	2,128,955		$	2,576,467		$	5,749,207		$	6,704,164
Natural gas	169,601			258,961			1,224,161			1,736,701
Other	16,006			16,252			52,819			54,718
Total operating revenues	2,314,562			2,851,680			7,026,187			8,495,583

Operating expenses
Electric fuel and purchased power	982,103			1,513,935			2,703,952			3,871,437
Cost of natural gas sold and transported	71,638			155,804			809,791			1,298,731
Cost of sales — other	4,915			4,528			14,268			14,095
Other operating and maintenance expenses	466,465			422,560			1,410,760			1,340,362
Conservation and demand side management program expenses	47,157			27,483			133,793			92,278
Depreciation and amortization	198,222			209,131			609,285			622,512
Taxes (other than income taxes)	78,914			70,245			229,025			218,220
Total operating expenses	1,849,414			2,403,686			5,910,874			7,457,635

Operating income	465,148			447,994			1,115,313			1,037,948

Other income (expense), net	(977		)	9,736			4,394			27,270
Allowance for funds used during construction — equity	18,618			16,319			55,565			45,478

Interest charges and financing costs
Interest charges — includes other financing costs of $5,103, $5,162, $15,255 and $15,294, respectively	139,347			139,777			420,447			405,671
Allowance for funds used during construction — debt	(9,598		)	(9,625		)	(29,671		)	(28,748		)
Total interest charges and financing costs	129,749			130,152			390,776			376,923

Income from continuing operations before income taxes and equity earnings	353,040			343,897			784,496			733,773

Income taxes	135,610			121,551			280,581			252,765
Equity earnings of unconsolidated subsidiaries	4,363			349			10,760			1,154

Income from continuing operations	221,793			222,695			514,675			482,162
Income (loss) from discontinued operations, net of tax	(965		)	94			(2,673		)	(684		)
Net income	220,828			222,789			512,002			481,478
Dividend requirements on preferred stock	1,060			1,060			3,180			3,180
Earnings available to common shareholders	$	219,768		$	221,729		$	508,822		$	478,298

Weighted average common shares outstanding:
Basic	456,769			434,131			456,095			431,511
Diluted	457,453			439,397			456,729			436,716
Earnings per average common share:
Basic	$	0.48		$	0.51		$	1.12		$	1.11
Diluted	0.48			0.51			1.11			1.10
Cash dividends declared per common share	0.25			0.24			0.73			0.71

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 Sept. 30,						Nine Months Ended Sept. 30,
Diluted earnings (loss) per share	2009			2008			2009			2008
Public Service Company of Colorado (PSCo)	$	0.20		$	0.20		$	0.51		$	0.56
NSP-Minnesota	0.20			0.25			0.48			0.51
NSP-Wisconsin	0.03			0.03			0.08			0.07
Southwestern Public Service Company (SPS)	0.08			0.05			0.14			0.06
Equity earnings of unconsolidated subsidiaries (WYCO)	0.01			0.01			0.02			0.01
Regulated utility — continuing operations (Note 2)	0.52			0.54			1.23			1.21
Holding company and other costs	(0.04		)	(0.03		)	(0.11		)	(0.11		)
Ongoing(a) diluted earnings per share	0.48			0.51			1.12			1.10
PSR Investments Inc. (PSRI)	—			—			(0.01		)	—
GAAP diluted earnings per share	$	0.48		$	0.51		$	1.11		$	1.10

(a) Ongoing earnings exclude the impact related to the Corporate Owned Life Insurance (COLI) program. 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.

PSCo — Earnings at PSCo were flat for the third quarter and decreased by five cents per share for the nine months ending Sept. 30, 2009, largely due to the negative impact of weather and rising costs. The decrease was partially offset by new electric rates that went into effect in July 2009. In May 2009, the Colorado Public Utilities Commission (CPUC) approved an annual electric rate increase of $112 million.

NSP-Minnesota — Earnings at NSP-Minnesota decreased by five cents per share for the third quarter and by three cents per share for the nine months ending Sept. 30, 2009. The decrease is mainly due to the negative impact of weather, an increase in the effective tax rate and timing of nuclear outage expenses. The decrease was partially offset by an electric rate increase that went into effect in January 2009.

NSP-Wisconsin — Earnings at NSP-Wisconsin were flat for the third quarter and increased by one cent per share for the nine months ending Sept. 30, 2009, largely due to improved fuel recovery and new rates which were effective in January 2009.

SPS — Earnings at SPS increased by three cents per share for the third quarter and by eight cents per share for the nine months ending Sept. 30, 2009. The 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.

WYCO — Equity earnings of unconsolidated subsidiaries were flat for the third quarter and increased by one cent per share for the nine months ending Sept. 30, 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 storage facility that commenced operations in July 2009.

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			Nine Months
	Ended Sept. 30,			Ended Sept. 30,
2008 GAAP and ongoing(a) diluted earnings per share	$	0.51		$	1.10

Components of change — 2009 vs. 2008

Higher electric margins	0.12			0.30
Lower depreciation and amortization expenses	0.02			0.02
Higher allowance for funds used during construction — equity	0.01			0.02
Higher operating and maintenance expenses	(0.06		)	(0.10		)
Higher conservation and DSM expenses (generally offset in revenues)	(0.03		)	(0.06		)
Lower other income (expense), net	(0.02		)	(0.03		)
Dilution from DRIP, benefit plan and the 2008 common equity issuance	(0.02		)	(0.05		)
Higher taxes, other than income taxes	(0.01		)	(0.02		)
Lower natural gas margins	(0.01		)	(0.03		)
Higher interest expenses	—			(0.02		)
Other, including higher effective tax rate	(0.03		)	(0.01		)
2009 GAAP diluted earnings per share	0.48			1.12
PSR Investments Inc. (PSRI)	—			(0.01		)
2009 ongoing(a) diluted earnings per share	$	0.48		$	1.11

(a) Ongoing earnings exclude the impact related to the COLI program. 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.

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 Sept. 30,									Nine Months Ended Sept. 30,
	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	)	$	(0.05	)	$	(0.01	)	$	(0.04	)
Firm natural gas	—			—			—			(0.01		)	0.01			(0.02		)
Total	$	(0.05	)	$	(0.01	)	$	(0.04	)	$	(0.06	)	$	—		$	(0.06	)

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

	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	Actual		Normalized		Actual		Normalized
Electric residential	(3.6	)%	2.8	%	(2.3	)%	0.5	%
Electric commercial and industrial	(3.9	)	(2.2	)	(3.3	)	(2.6	)
Total retail electric sales	(3.8	)	(0.8	)	(3.0	)	(1.7	)
Firm natural gas sales	(3.4	)	(2.0	)	(7.0	)	0.7

Electric — Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation of natural gas prices used in the generation of electricity, but has little impact on electric margin. The following tables detail the electric revenues and margin:

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Millions of Dollars)	2009			2008			2009			2008
Electric revenues	$	2,129		$	2,576		$	5,749		$	6,704
Electric fuel and purchased power	(982		)	(1,514		)	(2,704		)	(3,871		)
Electric margin	$	1,147		$	1,062		$	3,045		$	2,833

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

	Three Months			Nine Months
	Ended Sept. 30,			Ended Sept. 30,
(Millions of Dollars)	2009 vs. 2008			2009 vs. 2008
Retail rate increases (Colorado, Minnesota, Texas, New Mexico and Wisconsin)	$	98		$	190
Conservation and DSM revenues (generally offset by expenses)	20			53
2008 refund of nuclear refueling outage revenues due to change in recovery method	14			15
Non-fuel riders	4			18
Metropolitan Emissions Reduction Project (MERP) rider	3			13
NSP-Wisconsin fuel recovery	3			10
Firm wholesale	2			10
Estimated impact of weather	(26		)	(24		)
NSP-Minnesota rate case provision for refund (largely offset in depreciation expense)	(25		)	(30		)
Purchased capacity costs	(11		)	(44		)
Sales mix and demand revenues	(5		)	10
Retail sales decline (excluding weather impact)	—			(17		)
SPS 2008 fuel cost allocation regulatory accruals	—			12
Other, net	8			(4		)
Total increase in electric margin	$	85		$	212

Xcel Energy has experienced a decline in megawatt hours (MwH) sales, which we believe is driven by overall economic conditions and to a lesser degree, increased conservation efforts. Our most significant declines have occurred in commercial and industrial sales, which are directly related to the economic downturn. The declines in MwH sales to the commercial and industrial customer class are partially offset by demand fees, 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 Sept. 30,						Nine Months Ended Sept. 30,
(Millions of Dollars)	2009			2008			2009			2008
Natural gas revenues	$	170		$	259		$	1,224		$	1,737
Cost of natural gas sold and transported	(72		)	(156		)	(810		)	(1,299		)
Natural gas margin	$	98		$	103		$	414		$	438

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

	Three Months			Nine Months
	Ended Sept. 30,			Ended Sept. 30,
(Millions of Dollars)	2009 vs. 2008			2009 vs. 2008
Sales mix	$	(2	)	$	(4	)
Transportation margin	(2		)	(2		)
Estimated impact of weather	(1		)	(13		)
Conservation and DSM revenues (generally offset by expenses)	1			2
Other, net	(1		)	(7		)
Total decrease in natural gas margin	$	(5	)	$	(24	)

Other Operating and Maintenance (O&M) Expenses — O&M expenses increased by approximately $43.9 million, or 10.4 percent, for the third quarter and approximately $70.4 million, or 5.3 percent for the first nine months of 2009, compared with 2008. The following table summarizes the changes in other O&M expenses:

	Three Months			Nine Months
	Ended Sept. 30,			Ended Sept. 30,
(Millions of Dollars)	2009 vs. 2008			2009 vs. 2008
Nuclear outage costs, net of deferral	$	27		$	26
Higher employee benefit costs	15			40
Higher nuclear plant operation costs	4			20
Higher plant generation costs	3			5
Lower consulting costs	(7		)	(19		)
Other, net	2			(2		)
Total increase in other operating and maintenance expenses	$	44		$	70

· The increase in nuclear outage costs is due to the timing of outages in conjunction with 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 the third quarter of 2008.

· Higher employee benefits costs are primarily attributable to increased pension costs, in part, related to market losses on retirement benefit plan assets as well as higher employee medical plan costs.

· 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 implemented in early 2009.

Conservation and Demand Side Management (DSM) Program Expenses — Conservation and DSM program expenses increased approximately $19.7 million for the third quarter of 2009, and by $41.5 million for the first nine months of 2009, compared with the same periods in 2008. The higher expense is attributable to the expansion of programs and regulatory commitments. Conservation and DSM program expenses are generally recovered through riders in our major jurisdictions or through base rates with tracker mechanisms.

Depreciation and Amortization — Depreciation and amortization expenses decreased by approximately $10.9 million, or 5.2 percent, for the third quarter of 2009, and by $13.2 million, or 2.1 percent, for the first nine months of 2009, compared with the same periods in 2008. In September 2009, as a result of the Minnesota Public Utilities Commission (MPUC) decision in the Minnesota electric rate case, NSP-Minnesota began recognizing a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation, effective Jan. 1, 2009. In addition, in June 2009, the MPUC extended the recovery period of decommissioning expense by 10 years for the Prairie Island and the Monticello nuclear plants. These decreases were partially offset by normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $8.7 million, or 12.3 percent, for the third quarter of 2009, and by $10.8 million, or 5.0 percent, for the first nine months of 2009, compared with the same periods in 2008. The increase is primarily due to increased property taxes.

Other Income (Expense), Net — Other income (expense), net, decreased $10.7 million during the third quarter of 2009 and $22.9 million for the first nine months of 2009, compared with the same periods in 2008. The net decline is 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.

Allowance for Funds Used During Construction, Equity and Debt (AFDC) — AFDC increased by approximately $2.3 million, or 8.8 percent, for the third quarter of 2009, and by $11.0 million, or 14.8 percent, for the first nine months of 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 which is expected to be completed in the fourth quarter of 2009, as well as other construction projects.

Interest Charges — Interest charges decreased by approximately $0.4 million, or 0.3 percent, for the third quarter of 2009 and increased by $14.8 million, or 3.6 percent, for the first nine months of 2009, compared with the same periods in 2008. The lower interest expense in the third quarter was largely due to a maturing bond at NSP-Minnesota that was repaid by issuing lower-cost short-term debt. This short-term debt is expected to be refinanced with long-term debt later in the year. The year-to-date increase was primarily the result of increased debt levels to fund new capital investments.

Income Taxes — Income tax expense for continuing operations increased by $14.1 million for the third quarter of 2009, compared with 2008. The effective tax rate for continuing operations was 38.4 percent for the third quarter of 2009, compared with 35.3 percent for the same period in 2008. Income tax expense for continuing operations increased by $27.8 million for the first nine months of 2009, compared with the first nine months of 2008. The effective tax rate for continuing operations was 35.8 percent for the first nine months of 2009, compared with 34.4 percent for the same period in 2008.

The higher effective tax rates were primarily due to the recognition of additional state unitary tax expense and the establishment of a valuation allowance against certain state tax credit carryovers that are now expected to expire, which was partially offset by wind energy production tax credits. Excluding these expense items, the effective tax rate for the third quarter and first nine months of 2009 would have been 36.4 percent and 34.8 percent, respectively. We expect the effective tax rate for 2009 continuing operations to be approximately 34 percent to 36 percent.

Equity Earnings of Unconsolidated Subsidiaries — Equity earnings of unconsolidated subsidiaries increased by $4.0 million for the third quarter of 2009, and by $9.6 million for the first nine months of 2009, compared with the same periods in 2008. The increase is primarily due to higher earnings from the equity investment in WYCO as a result of the High Plains natural gas pipeline, located in Colorado, commencing operations in late 2008 as well as a storage facility that commenced operations in July 2009.

Note 3. Xcel Energy Capital Structure and Financing

Following is the capital structure of Xcel Energy at Sept. 30, 2009:

			Percentage
	Balance at		of Total
(Billions of Dollars)	Sept. 30, 2009		Capitalization
Current portion of long-term debt	$	0.2	1	%
Short-term debt	0.5		3
Long-term debt	7.9		50
Total debt	8.6		54

Preferred equity	0.1		1
Common equity	7.2		45
Total equity	7.3		46

Total capitalization	$	15.9	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.

NSP-Minnesota plans to issue $300 million of first mortgage bonds in November. The proceeds will be used to repay short-term debt, which was used to fund the payment of a $250 million unsecured note that matured on Aug. 1, 2009, and for general corporate purposes.

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 Oct. 21, 2009, 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	$	170.8	$	311.4	$	0.2	$	311.6	December 2011
PSCo	675.1		4.6		670.5		13.1		683.6		December 2011
SPS	247.9		10.0		237.9		3.6		241.5		December 2011
Xcel Energy – Holding Company	771.6		371.1		400.5		1.7		402.2		December 2011
NSP-Wisconsin(b)	—		—		—		21.8		21.8
Total	$	2,176.8	$	556.5	$	1,620.3	$	40.4	$	1,660.7

(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 5. Rates and Regulation

NSP-Minnesota Electric Rate Case — In November 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually. This request was later modified to $136 million.

In September 2009, the MPUC voted to approve a rate increase of approximately $91.4 million. As part of its decision, the MPUC approved a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation and decommissioning expenses, effective Jan. 1, 2009. This decision reduced NSP-Minnesota’s overall revenue deficiency by approximately $40 million, while at the same time reducing expense accruals by a corresponding amount. A summary of the key terms is listed below:

	Revised Request	Approved
Rate increase	$136 million	$91 million
Return on equity (ROE)	11.0%	10.88%
Equity ratio	52.5%	52.5%
Electric rate base	$4.1 billion	$4.1 billion
Depreciation life extension for Prairie Island nuclear plant	0 years	10 years

As of Sept. 30, 2009, NSP-Minnesota accrued a customer refund of approximately $30.2 million to reflect the difference between interim rates that were implemented Jan. 2, 2009 and the amount approved by the MPUC. The written order was issued Oct. 23, 2009.

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 is 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. The proposed increase includes approximately $2.9 million in rider revenues; therefore, the requested increase, net of current riders, is approximately $15.7 million or 10.7 percent. Rates are expected to be effective in January 2010, based on statutory requirements in South Dakota. The procedural schedule is as follows:

· Staff and Intervenor Testimony – Nov. 20, 2009;

· Testimony – Dec. 4. 2009;

· Hearings – Dec. 9 – 11, 2009.

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 is 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 is comprised of a traditional base rate increase of $45.1 million offset by projected fuel decreases of $14.7 million.

On Oct. 21, 2009, Public Service Commission of Wisconsin (PSCW) staff and intervenors filed testimony. The PSCW staff recommended an increase of $14.5 million for 2010 based on a 10.75 percent ROE and a 51.63 percent equity ratio. The staff has proposed to apply the 2009 fuel over recovery against the increase such that there would be no change in rates for 2010. A summary of the adjusted request is listed below:

Millions of dollars	Request			PSCW Adjusted Request
Base non-fuel	$	45.1		$	36.8
Fuel	(14.7		)	(15.8		)
Prairie Island decommissioning	—			(6.5		)
Rate increase	$	30.4		$	14.5

The base non-fuel adjustments include: (1) an adjustment to the equity ratio from 53.12 percent to 51.63 percent on a regulatory basis; (2) a reduction to rate base to account for appropriated retained earnings associated with certain hydro licenses; (3) reduced interchange agreement fixed charge billings and (4) a disallowance of certain employee compensation expenses. In addition, the PSCW staff adjustments to the proposed increase include a $6.5 million reduction for Prairie Island nuclear plant decommissioning expense as a result of the 10-year life extension approved by the MPUC.

The Wisconsin Industrial Energy Group (WIEG) was the only intervenor to file direct testimony. WIEG objects to NSP-Wisconsin’s class cost of service study and proposed rate design, and recommends changes that would benefit its members.

A decision is expected by the end of 2009 with new rates in effect in January 2010. The procedural schedule is as follows:

· Rebuttal Testimony — Nov. 6, 2009;

· Surrebuttal Testimony — Nov. 10, 2009;

· Technical & Public Hearing — Nov. 11, 2009.

PSCo - 2010 Electric Rate Case — In May 2009, PSCo filed a request to increase electric rates in Colorado by $180.2 million, or 6.8 percent. The rate filing is based on a 2010 forecast test year, 11.25 percent ROE, rate base of $4.4 billion, and an equity ratio of 58.05 percent. Intervenors have filed testimony with the following current recommendations:

· The CPUC staff has recommended an increase of $70.5 million, based on an adjusted 2008 historic test year (adjusted for Comanche Unit 3 and Fort St. Vrain) and a 9.84 percent ROE. The main adjustments are related to ROE, elimination of incentive pay, and deferral of recovery of dismantling costs.

· The Colorado Office of Consumer Counsel (OCC) has recommended an increase of $33.2 million, based on an adjusted 2008 historic test year (adjusted for Comanche Unit 3 and Fort St. Vrain) and a 9.75 percent ROE. The main adjustments are related to ROE, a lower equity ratio of 53 percent, a cash working capital cost reduction, unbilled revenue, elimination of incentive pay, lower pension and benefit costs, and no recovery of future Innovative Clean Technology expense. The OCC recommended an increase of $87.8 million if a forward test year is accepted.

· Colorado Energy Consumers recommended an increase of up to $95.4 million, an adjusted 2008 historic test year and an ROE of 10.0 percent. The recommendation should be reduced to reflect adjustments by other intervenors.

· CF&I Steel, LP and Climax Molybdenum Co. recommended an increase of up to $98.4 million and an adjusted 2008 historic test year. The recommendation should be reduced to reflect adjustments by other intervenors.

In October 2009, PSCo filed rebuttal testimony and revised their request rate increase to $177.4 million and affirmed its requested ROE of 11.25 percent. The procedural schedule is as follows.

· Hearings	Oct. 26 — Nov. 6, 2009;
· Statements of Position	Nov. 16, 2009.

PSCo expects a decision before year end with new rates effective in January 2010.

Note 6. Xcel Energy Earnings Guidance

Based on current projections, we expect 2009 earnings to be near the mid-point of our guidance range of $1.45 to $1.55 per share. Key assumptions are detailed below:

·	Normal weather patterns are experienced for the remainder of the year.
·	Reasonable regulatory outcomes are achieved in various rate cases and other regulatory decisions which may occur during the year.
·	Various riders, associated with MERP, Minnesota and Colorado transmission and Minnesota renewable energy, are expected to increase revenue by approximately $50 million to $60 million over 2008 levels.
·	Weather adjusted electric retail sales decline by approximately 2 percent.
·	Weather adjusted retail firm natural gas sales decline by approximately 1 percent.
·	Capacity costs are projected to increase approximately $45 million over 2008 levels. Capacity costs at PSCo are recovered under the purchased capacity cost adjustment.
·	Operating and maintenance expenses are projected to increase $140 million over 2008 levels. In 2008, nuclear outage expense decreased due to a change in recovery method related to costs associated with refueling outages and there was no accrual in 2008 for the annual performance based incentive plan. The increase reflects the following:
	·	Nuclear (including outage amortization) — $55 million
	·	Pension and medical — $35 million
	·	Other —$50 million (including $35 million of incentive compensation)
·	Depreciation and amortization expense is projected to decline by approximately $10 million compared with 2008 levels. This reflects the recent MPUC decision to extend the depreciation life of the Prairie Island nuclear plant by 10 years.
·	Interest expense increases approximately $15 million to $20 million over 2008 levels.
·	Allowance for funds used during construction — equity is projected to increase by $10 million to $15 million over 2008 levels.
·	An effective tax rate for continuing operations of approximately 34 percent to 36 percent.
·	Average common stock and equivalents of approximately 457 million shares.

Note 7. Non-GAAP Reconciliation

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

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Thousands of Dollars)	2009			2008			2009			2008
Ongoing(a) earnings	$	222,131		$	223,275		$	516,970		$	482,535
PSRI	(338		)	(580		)	(2,295		)	(373		)
Total continuing operations	221,793			222,695			514,675			482,162
Income (loss) from discontinued operations	(965		)	94			(2,673		)	(684		)
GAAP earnings	$	220,828		$	222,789		$	512,002		$	481,478

(a) Ongoing earnings exclude the impact related to the COLI program. 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.

XCEL ENERGY INC. AND SUBSIDIARIES

UNAUDITED EARNINGS RELEASE SUMMARY

All amounts in thousands, except earnings per share

Three Months Ended Sept. 30,	2009			2008
Operating revenues:
Electric and natural gas revenues	$	2,298,556		$	2,835,428
Other	16,006			16,252
Total operating revenues	2,314,562			2,851,680

Income from continuing operations	221,793			222,695
Income from discontinued operations	(965		)	94
Net income	220,828			222,789

Earnings available to common shareholders	219,768			221,729
Weighted average diluted common shares outstanding	457,453			439,397

Components of Earnings per Share — Diluted
Regulated utility — continuing operations	0.52			0.54
Holding company and other costs	(0.04		)	(0.03		)
Ongoing(a) diluted earnings per share	0.48			0.51
PSRI	—			—
GAAP diluted earnings per share	$	0.48		$	0.51

Nine Months Ended Sept. 30,	2009			2008
Operating revenues:
Electric and natural gas revenues	$	6,973,368		$	8,440,865
Other	52,819			54,718
Total operating revenues	7,026,187			8,495,583

Income from continuing operations	514,675			482,162
Income from discontinued operations	(2,673		)	(684		)
Net income	512,002			481,478

Earnings available to common shareholders	508,822			478,298
Weighted average diluted common shares outstanding	456,729			436,716

Components of Earnings per Share — Diluted
Regulated utility — continuing operations	1.23			1.21
Holding company and other costs	(0.11		)	(0.11		)
Ongoing(a) diluted earnings per share	1.12			1.10
PSRI	(0.01		)	—
GAAP diluted earnings per share	$	1.11		$	1.10

Book value per share	$	15.76		$	15.27

(a) Ongoing earnings exclude the impact related to the COLI program. 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.

US Dial-In:	(877) 941-8610
International Dial-In:	(480) 629-9819
Conference ID:	4166774

Replay Numbers
US Dial-In:	(800) 406-7325
International Dial-In:	(303) 590-3030
Access Code:	4166774#

For more information, contact:
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

Exhibit 99.01