Xcel Energy (XEL) 8-K Results of Operations and Financial Condition

Exhibit 99.01

414 Nicollet Mall

Minneapolis, MN 55401

July 30, 2009

XCEL ENERGY INC. SECOND QUARTER 2009 EARNINGS

·GAAP (generally accepted accounting principles) second quarter diluted earnings per share were $0.25 in 2009, compared with $0.24 per share in 2008.

·Xcel Energy reaffirms its 2009 earnings guidance of $1.45 to $1.55 per diluted share.

MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) today reported second quarter 2009 earnings of $117 million, or $0.25 per diluted share, compared with $106 million, or $0.24 per diluted share, in 2008.

Higher second quarter 2009 earnings were primarily due to increases in electric margin as a result of constructive rate case outcomes (Minnesota interim, Texas, New Mexico and Wisconsin) and revenue from non-fuel riders, partially offset by a decline in retail electric sales, higher operating and maintenance expenses and other items.

“While the recession continues to take a toll on our electric retail sales, we had already instituted several cost management programs that will help to mitigate the negative impacts,” said Richard C. Kelly, chairman, president and chief executive officer.  “As a result, we are reaffirming our 2009 earnings guidance of $1.45 to $1.55 per share.”

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

US Dial-In:	(877) 941-0844
International Dial-In:	(480) 629-9645

The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website at www.xcelenergy.com.  To access the presentation, click on Investor Information.  If you are unable to participate in the live event, the call will be available for replay from 12:00 p.m. CDT on July 30 through 11:59 p.m. CDT on July 31.

Replay Numbers
US Dial-In:	(800) 406-7325
International Dial-In:	(303) 590-3030
Access Code:	4103933#

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Except for the historical statements contained in this release, the matters discussed herein, including our 2009 full year EPS guidance and assumptions, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including 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 Exhibit 99.01 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2008.

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

This information is not given in connection with any

sale, offer for sale or offer to buy any security.

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(amounts in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues
Electric	$	1,733,695		$	2,154,383		$	3,620,252		$	4,127,697
Natural gas	265,884			443,613			1,054,560			1,477,740
Other	16,504			17,519			36,813			38,466
Total operating revenues	2,016,083			2,615,515			4,711,625			5,643,903
Operating expenses
Electric fuel and purchased power	797,101			1,269,422			1,721,849			2,357,502
Cost of natural gas sold and transported	146,388			319,800			738,153			1,142,927
Cost of sales — other	3,987			4,114			9,353			9,567
Other operating and maintenance expenses	472,401			456,781			944,295			917,802
Conservation and demand side management program expenses	41,417			29,226			86,636			64,795
Depreciation and amortization	202,348			207,774			411,063			413,381
Taxes (other than income taxes)	73,073			68,562			150,111			147,975
Total operating expenses	1,736,715			2,355,679			4,061,460			5,053,949
Operating income	279,368			259,836			650,165			589,954
Interest and other income, net	3,019			9,161			5,371			17,534
Allowance for funds used during construction — equity	18,720			14,939			36,947			29,159
Interest charges and financing costs
Interest charges — includes other financing costs of $5,114, $5,141, $10,152 and $10,132, respectively	139,297			133,723			281,100			265,894
Allowance for funds used during construction — debt	(9,845		)	(9,596		)	(20,073		)	(19,123		)
Total interest charges and financing costs	129,452			124,127			261,027			246,771
Income from continuing operations before income taxesand equity earnings	171,655			159,809			431,456			389,876
Income taxes	57,846			54,819			144,971			131,213
Equity earnings of unconsolidated subsidiaries	3,255			483			6,397			805
Income from continuing operations	117,064			105,473			292,882			259,468
Income (loss) from discontinued operations, net of tax	43			99			(1,708		)	(778		)
Net income	117,107			105,572			291,174			258,690
Dividend requirements on preferred stock	1,060			1,060			2,120			2,120
Earnings available to common shareholders	$	116,047		$	104,512		$	289,054		$	256,570
Weighted average common shares outstanding:
Basic	456,307			430,811			455,753			430,187
Diluted	456,766			435,868			456,362			435,360
Earnings per average common share:
Basic	$	0.25		$	0.24		$	0.63		$	0.60
Diluted	0.25			0.24			0.63			0.59
Cash dividends declared per common share	0.25			0.24			0.48			0.47

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XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Investor Relations Earnings Release (Unaudited)

Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.

Note 1.  Earnings per Share Summary

The following table summarizes the diluted earnings per share for Xcel Energy:

	Three Months Ended June 30,						Six Months Ended June 30,
Diluted earnings (loss) per share	2009			2008			2009			2008
Public Service Company of Colorado (PSCo)	$	0.13		$	0.15		$	0.31		$	0.37
NSP-Minnesota	0.11			0.11			0.27			0.26
NSP-Wisconsin	0.01			0.01			0.06			0.04
Southwestern Public Service Company (SPS)	0.03			0.01			0.06			—
Equity earnings of unconsolidated subsidiaries (WYCO)	0.01			—			0.01			—
Regulated utility — continuing operations (Note 2)	0.29			0.28			0.71			0.67
Holding company and other costs	(0.04		)	(0.04		)	(0.07		)	(0.08		)
Ongoing(a) diluted earnings per share	0.25			0.24			0.64			0.59
PSR Investments Inc. (PSRI)	—			—			(0.01		)	—
GAAP diluted earnings per share	$	0.25		$	0.24		$	0.63		$	0.59

(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.

Earnings at PSCo declined by two cents per share for the second quarter and six cents per share for the six months ending June 30, 2009, largely due to rising costs and relatively flat weather adjusted electric and natural gas sales margin.  In May 2009, the Colorado Public Utility Commission (CPUC) approved an annual electric rate increase of $112 million and rates went into effect in July 2009.

Earnings at NSP-Minnesota were flat for the second quarter and increased by one cent per share for the six months ending June 30, 2009.  In Minnesota, there is a pending rate case with interim rates, subject to refund, which went into effect in January 2009. These interim rates provided incremental revenue and cost recovery, which offset declining sales and rising costs.

Earnings at NSP-Wisconsin were flat for the second quarter and increased by two cents per share for the six months ending June 30, 2009, largely due to improved fuel recovery and new rates which were effective in January 2009.

Earnings at SPS increased by two cents per share for the second quarter and by six cents per share for the six months ending June 30, 2009, primarily due to electric rate increases in Texas (effective in February 2009) and New Mexico and the 2008 resolution of certain fuel cost allocation issues, which were partially offset by higher purchased capacity costs.

Equity earnings of unconsolidated subsidiaries increased by one cent per share for the second quarter and for the six months ending June 30, 2009, due to our investment in WYCO, which owns a new gas pipeline in Colorado that began operations in late 2008.

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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			Six Months
	Ended June 30			Ended June 30
2008 GAAP and ongoing(a) diluted earnings per share	$	0.24		$	0.59
Components of change — 2009 vs. 2008
Higher electric margins	0.07			0.18
Higher allowance for funds used during construction — equity	0.01			0.02
Lower depreciation and amortization expenses	0.01			—
Higher operating and maintenance expenses	(0.02		)	(0.04		)
Higher conservation and DSM expenses (generally offset in revenue)	(0.02		)	(0.03		)
Dilution from DRIP, benefit plan and the 2008 common equity issuance	(0.01		)	(0.03		)
Higher interest expenses	(0.01		)	(0.02		)
Lower natural gas margins	(0.01		)	(0.03		)
Other	(0.01		)	(0.01		)
2009 GAAP diluted earnings per share	0.25			0.63
PSR Investments Inc. (PSRI)	—			0.01
2009 ongoing(a) diluted earnings per share	$	0.25		$	0.64

(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 June 30,								Six Months Ended June 30,
	2009 vs.			2008 vs.			2009 vs.		2009 vs.			2008 vs.			2009 vs.
	Normal			Normal			2008		Normal			Normal			2008
Retail electric	$	(0.01	)	$	(0.02	)	$	0.01	$	(0.01	)	$	(0.01	)	$	—
Firm natural gas	—			—			—		(0.01		)	0.01			(0.02		)
Total	$	(0.01	)	$	(0.02	)	$	0.01	$	(0.02	)	$	—		$	(0.02	)

Sales  — The following table summarizes Xcel Energy’s sales increases and decreases for the three and six months ended June 30, respectively, 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 June 30,				Six Months Ended June 30,
	Actual		Normalized		Actual		Normalized
Electric residential	(0.6	)%	(0.7	)%	(1.6	)%	(0.7	)%
Electric commercial and industrial	(4.1	)	(4.2	)	(3.0	)	(2.8	)
Total retail electric sales	(3.2	)	(3.2	)	(2.6	)	(2.2	)
Firm natural gas sales	0.4		8.3		(7.4	)	1.1

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Electric—  The following tables detail the electric revenues and margin:

	Three Months Ended June 30,						Six Months Ended June 30,
(Millions of Dollars)	2009			2008			2009			2008
Electric revenues	$	1,734		$	2,154		$	3,620		$	4,128
Electric fuel and purchased power	(797		)	(1,269		)	(1,722		)	(2,358		)
Electric margin	$	937		$	885		$	1,898		$	1,770

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

	Three Months			Six Months
	Ended June 30,			Ended June 30,
(Millions of Dollars)	2009 vs. 2008			2009 vs. 2008
Retail rate increases (Minnesota interim, Texas, Wisconsin and New Mexico)	$	43		$	84
Conservation and DSM revenues (generally offset by O&M expenses)	16			34
Sales mix and demand revenues	8			15
Estimated impact of weather	7			1
Non-fuel riders	6			14
Firm wholesale	6			9
Metropolitan Emissions Reduction Project (MERP) rider	4			10
SPS 2008 fuel cost allocation regulatory accruals	—			12
Retail sales decline (excluding weather impact)	(16		)	(18		)
Purchased capacity costs	(15		)	(33		)
NSP-Wisconsin fuel recovery	(2		)	7
Other, net	(5		)	(7		)
Total increase in electric margin	$	52		$	128

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 June 30,						Six Months Ended June 30,
(Millions of Dollars)	2009			2008			2009			2008
Natural gas revenues	$	266		$	444		$	1,055		$	1,478
Cost of natural gas sold and transported	(146		)	(320		)	(738		)	(1,143		)
Natural gas margin	$	120		$	124		$	317		$	335

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

	Three Months			Six Months
	Ended June 30,			Ended June 30,
(Millions of Dollars)	2009 vs. 2008			2009 vs. 2008
Estimated impact of weather	$	(3	)	$	(12	)
Conservation and DSM revenues (generally offset by O&M expenses)	2			1
Other, net	(3		)	(7		)
Total decrease in natural gas margin	$	(4	)	$	(18	)

Other Operating and Maintenance (O&M) Expenses — O&M expenses increased by approximately $15.6 million, or 3.4 percent, for the second quarter and approximately $26.5 million, or 2.9 percent for the first six months of 2009, compared with 2008.  The following table summarizes the changes in other O&M expenses:

	Three Months			Six Months
	Ended June 30,			Ended June 30,
(Millions of Dollars)	2009 vs. 2008			2009 vs. 2008
Nuclear outage costs, net of deferral	$	10		$	(1	)
Higher employee benefit costs	9			25
Higher nuclear plant operation costs	8			16
Lower consulting costs	(7		)	(11		)
Lower material costs	(3		)	(4		)
Other, net	(1		)	2
Total increase in other operating and maintenance expenses	$	16		$	27

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.

Conservation and Demand Side Management (DSM) Program Expenses — Conservation and DSM expenses increased approximately $12.2 million, for the second quarter of 2009, and by $21.8 million for the first six 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 $5.4 million, or 2.6 percent, for the second quarter of 2009, and by $2.3 million, or 0.6 percent, for the first six months of 2009, compared with the same periods in 2008.  Higher depreciation due to normal system expansion was offset by a decrease in decommissioning  expense as the recovery periods for the Prairie Island and the Monticello nuclear plants were both extended. Those recovery periods were approved by the MPUC in June 2009.

Allowance for Funds Used During Construction, Equity and Debt (AFDC) — AFDC increased by approximately $4.0 million, or 16.4 percent, for the second quarter of 2009, and by $8.7 million, or 18.1 percent, for the first six 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 by completed in the fourth quarter of 2009, as well as other construction projects.

Interest Charges — Interest charges increased by approximately $5.6 million, or 4.2 percent, for the second quarter of 2009,  and by $15.2 million, or 5.7 percent, for the first six months of 2009, compared with the same periods in 2008.  The increase was primarily the result of increased debt levels to fund new capital investments.

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Income Taxes — Income tax expense for continuing operations increased by $3.0 million for the second 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 33.7 percent for the second quarter of 2009, compared with 34.3 percent for the same period in 2008. The lower effective tax rate for the second quarter of 2009 was primarily due to a decrease in the forecasted annual effective tax rate for 2009 as compared to 2008.

Income tax expense for continuing operations increased by $13.8 million for the first six months of 2009, compared with the first six months of 2008.  The increase in income tax expense was primarily due to an increase in pretax income. The effective tax rate for continuing operations was 33.6 percent for the first six months of 2009, compared with 33.7 percent for the same period in 2008.

Equity Earnings of Unconsolidated Subsidiaries — Equity earnings of unconsolidated subsidiaries increased by $2.8 million for the second quarter of 2009, and by $5.6 million, for the first six 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 gas pipeline, located in Colorado, commencing operations in late 2008.

Note 3. Xcel Energy Capital Structure and Financing

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

(Billions of Dollars)	Balance at June 30, 2009		Percentage of Total Capitalization
Current portion of long-term debt	$	0.4	2	%
Short-term debt	0.4		2
Long-term debt	8.1		51
Total debt	8.9		55
Preferred equity	0.1		1
Common equity	7.1		44
Total equity	7.2		45
Total capitalization	$	16.1	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’s current debt financing plans for 2009 include the following:

·In June 2009, PSCo issued $400 million of first mortgage bonds with a 10-year maturity and a coupon of 5.125 percent.  The proceeds were used to fund payment of a $200 million 6.875 percent unsecured note that matured on July 15, 2009, to pay down short-term debt and for general corporate purposes.

·NSP-Minnesota plans to issue up to $400 million of first mortgage bonds this fall.  The proceeds will be used to  fund payment of a $250 million unsecured note maturing on Aug. 1, 2009, to pay down short-term debt and for general corporate purposes.

In addition, during 2009, Xcel Energy repaid the following securities, which were funded by existing cash resources, primarily from bonds issued in 2008.

·Redeemed the NSP-Wisconsin 7.375 percent $65 million first mortgage bonds, due Dec. 1, 2026.

·Retired the SPS 6.2 percent $100 million of unsecured senior A notes, due March 1, 2009.

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

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Note 4.  Liquidity

Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, preferred securities and hybrid securities to maintain desired capitalization ratios.

Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on financing needs for construction expenditures, working capital and dividend payments.

Commercial Paper — Xcel Energy, NSP-Minnesota, PSCo and SPS each have individual commercial paper programs. The Board authorized levels for these commercial paper programs are:

·$800 million for Xcel Energy;

·$500 million for NSP-Minnesota;

·$700 million for PSCo; and

·$250 million for SPS.

Xcel Energy and Utility Subsidiary Credit Facilities — As of July 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	$	5.8	$	476.4	$	0.4	$	476.8	December 2011
PSCo	675.1		4.6		670.5		11.2		681.7		December 2011
SPS	247.9		10.0		237.9		35.2		273.1		December 2011
Xcel Energy – Holding Company	771.6		407.1		364.5		3.0		367.5		December 2011
NSP-Wisconsin(b)	—		—		—		15.5		15.5
Total	$	2,176.8	$	427.5	$	1,749.3	$	65.3	$	1,814.6

(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.

Credit Agency Ratings — The access and cost of short-term and long-term borrowings are affected by regulatory actions, capital markets conditions and credit agency ratings. The following ratings reflect the views of Moody’s Investor Services, Inc., Standard & Poor’s Ratings Services, and Fitch Ratings.  A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.

On June 10, 2009, Standard & Poor’s affirmed its credit ratings and revised the outlook on Xcel Energy and its rated subsidiaries to positive from stable.  As of July 29, 2009, the following represents the credit ratings assigned to various Xcel Energy companies.

Company	Credit Type	Moody’s	S & P’s	Fitch
Xcel Energy	Senior Unsecured Debt	Baa1	BBB	BBB+
Xcel Energy	Commercial Paper	P-2	A-2	F2
NSP-Minnesota	Senior Unsecured Debt	A3	BBB+	A
NSP-Minnesota	Senior Secured Debt	A2	A	A+
NSP-Minnesota	Commercial Paper	P-2	A-2	F1
NSP-Wisconsin	Senior Unsecured Debt	A3	A-	A
NSP-Wisconsin	Senior Secured Debt	A2	A	A+
PSCo	Senior Unsecured Debt	Baa1	BBB+	A-
PSCo	Senior Secured Debt	A3	A	A
PSCo	Commercial Paper	P-2	A-2	F2
SPS	Senior Unsecured Debt	Baa1	BBB+	BBB+
SPS	Commercial Paper	P-2	A-2	F2

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Note 5.  Rates and Regulation

NSP-Minnesota Electric Rate Case — In November 2008, NSP-Minnesota filed a request with the Minnesota Public Utilities Commission  (MPUC) to increase Minnesota electric rates by $156 million annually, or 6.05 percent.  The request is based on a 2009 forecast test-year, an electric rate base of $4.1 billion, a requested return on equity (ROE) of 11.0 percent and an equity ratio of 52.5 percent.

In December 2008, the MPUC approved an interim rate increase of $132 million, subject to refund, or 5.12 percent, effective Jan. 2, 2009.  The primary difference between interim rate levels approved and NSP-Minnesota’s request of  $156 million is due to a previously authorized ROE of 10.54 percent and NSP-Minnesota’s requested ROE of 11.0 percent.

Intervenor and company testimony was filed during the spring and hearings were completed before an administrative law judge (ALJ) in June 2009.  NSP-Minnesota’s request has been adjusted and currently seeks a rate increase of approximately $136 million. In addition, NSP-Minnesota has offered an alternative proposal to reflect a three-year life extension for both decommissioning and depreciation expense accruals for the Prairie Island nuclear plant.  The revenue requirement under NSP-Minnesota’s alternative proposal was approximately $119 million.

At the time of hearing, the Office of Energy Security (OES) revised its request to $90 million, based on a ROE of 10.88 percent and an equity ratio of 52.5 percent.  The recommended revenue increase included recognition of a 10-year life extension of the Prairie Island nuclear plant, resulting in a decrease of approximately $40 million in depreciation and decommissioning expenses.  Other than the appropriate extension period for Prairie Island decommissioning and depreciation, the difference between NSP-Minnesota’s position and the OES is approximately $6 million. The Office of Attorney General has one remaining unresolved financial issue related to cost allocations whereby it is seeking a disallowance of approximately $3.4 million.

The ALJ is expected to issue a recommended decision in late August 2009, and a final decision from the MPUC is expected in October 2009.

NSP-Minnesota - South Dakota Electric Rate Case— On June 30, 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 on or before Jan. 31, 2010, based on statutory requirements in South Dakota.

NSP-Wisconsin - Electric and Gas Rate Case— On June 1, 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.  A decision is expected by the end of 2009 with new rates in effect in January 2010.

PSCo - 2009 Electric Rate Case — In November 2008, PSCo filed for a rate increase of approximately $174.7 million or 7.4 percent.  The rate filing was based on a 2009 forecast test-year, an ROE of 11.0 percent, an equity ratio of 58.08 percent and an electric rate base of approximately $4.2 billion.  In March 2009, PSCo filed rebuttal testimony and revised its request to a rate increase of $159.3 million.

In May 2009, the CPUC approved a black box settlement, which provides for a $112.2 million rate increase.  Rates went into effect in July 2009.  The main difference from the rebuttal case is the removal of the return on construction work in progress, which reduced PSCo’s request by approximately $40 million.  PSCo will continue to record AFDC income until Comanche Unit 3 is placed into service.

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PSCo — 2010 Electric Rate Case — On May 1, 2009, PSCo filed a request to increase electric rates in Colorado by $180 million.  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.  The procedural schedule is as follows.

·	Intervenor Testimony	Sept. 4, 2009
·	Cross & Rebuttal Testimony	Oct. 13, 2009
·	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.

SPS — Texas Retail Electric Rate Case — In June 2008, SPS filed to increase Texas rates by $61.3 million or approximately 5.9 percent.  Base revenues were proposed to increase by $94.4 million, while fuel and purchased power declined $33.1 million primarily due to fuel savings from the Lea Power Partners LLC (LPP) purchase power agreement.   The request was based on a 2007 test-year, an ROE of 11.25 percent, an electric rate base of $989.4 million and an equity ratio of 51.0 percent.

In January 2009, a settlement agreement was reached with various intervenors, which provided for a base rate increase of $57.4 million, a reduced depreciation expense of $5.6 million, allowed SPS to implement the transmission rider in 2009 and precludes SPS from filing to seek any other change in base rates until Feb. 15, 2010.  In January 2009, an ALJ approved interim rates effective February 2009.

On June 2, 2009, The Public Utility Commission of Texas issued its order approving the settlement.

SPS — New Mexico Retail Electric Rate Case — In December 2008, SPS filed with the New Mexico Public Regulation Commission (NMPRC) a request to increase electric rates by approximately $24.6 million, or 6.2 percent. The request is based on a historic test-year (split year based on year-ending June 30, 2008), an electric rate base of $321 million, an equity ratio of 50.0 percent and a requested ROE of 12.0 percent.  SPS also requested interim rates of $7.6 million to recover capacity costs of the Lea Power facility, which became operational in September 2008.

On March 26, 2009, the NMPRC approved a partial stipulated settlement between the parties that allows SPS to recover approximately $5.7 million of interim rates, effective May 1, 2009, through an LPP cost rider until the final rates from the remainder of the case are effective.

On May 28, 2009, the parties filed an uncontested stipulation that resolves all issues in the case.   Under the terms of the settlement, SPS would receive a base rate increase of $14.2 million.  In addition, SPS has agreed that it would not file its next rate case before Dec. 1, 2010, subject to a force majeure provision triggered by additional environmental compliance costs.  In July 2009, the NMPRC approved the stipulation and SPS implemented the new rates on July 15, 2009.

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Note 6.  Xcel Energy Earnings Guidance

Xcel Energy’s 2009 earnings guidance is $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 in the Minnesota electric rate case and other regulatory decision 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 over 2008 levels:

· Nuclear (including outage amortization) — $55 million

· Pension and medical — $35 million

· Other — $35 million to $85 million (including $45 million of incentive compensation)

· Depreciation and amortization expense is projected to increase approximately $20 million to $30 million over 2008.

· Interest expense increases approximately $10 million to $20 million over 2008 levels.

· Allowance for funds used during construction — equity is projected to increase by $5 million to $10 million over 2008 levels.

· An effective tax rate for continuing operations of approximately 33 percent to 35 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 June 30,					Six Months Ended June 30,
(Thousands of Dollars)	2009			2008		2009			2008
Ongoing(a) earnings	$	117,751		$	103,922	$	294,839		$	259,261
PSRI	(687		)	1,551		(1,957		)	207
Total continuing operations	117,064			105,473		292,882			259,468
Income (loss) from discontinued operations	43			99		(1,708		)	(778		)
GAAP earnings	$	117,107		$	105,572	$	291,174		$	258,690

(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.

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XCEL ENERGY INC. AND SUBSIDIARIES

UNAUDITED EARNINGS RELEASE SUMMARY

All amounts in thousands, except earnings per share

Three Months Ended June 30,	2009			2008
Operating revenues:
Electric and natural gas revenues	$	1,999,579		$	2,597,996
Other	16,504			17,519
Total operating revenues	2,016,083			2,615,515
Income from continuing operations	117,064			105,473
Income from discontinued operations	43			99
Net income	117,107			105,572
Earnings available to common shareholders	116,047			104,512
Weighted average diluted common shares outstanding	456,766			435,868
Components of Earnings per Share — Diluted
Regulated utility — continuing operations	0.29			0.28
Holding company and other costs	(0.04		)	(0.04		)
Ongoing(a) diluted earnings per share	0.25			0.24
PSRI	—			—
GAAP diluted earnings per share	$	0.25		$	0.24

Six Months Ended June 30,	2009			2008
Operating revenues:
Electric and natural gas revenues	$	4,674,812		$	5,605,437
Other	36,813			38,466
Total operating revenues	4,711,625			5,643,903
Income from continuing operations	292,882			259,468
Loss from discontinued operations	(1,708		)	(778		)
Net income	291,174			258,690
Earnings available to common shareholders	289,054			256,570
Weighted average diluted common shares outstanding	456,362			435,360
Components of Earnings per Share — Diluted
Regulated utility — continuing operations	0.71			0.67
Holding company and other costs	(0.07		)	(0.08		)
Ongoing(a) diluted earnings per share	0.64			0.59
PSRI	(0.01		)	—
GAAP diluted earnings per share	$	0.63		$	0.59
Book value per share	$	15.52		$	14.79

(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.

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