PUBLIC SERVICE CO OF COLORADO - FORM 8-K - EX-99.01 - EXHIBIT 99.01

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8-K - XCEL ENERGY 8-K 10-27-2011 - PUBLIC SERVICE CO OF COLORADO	form8k.htm

Exhibit 99.01

	414 Nicollet Mall
	Minneapolis, MN 55401

Oct. 27, 2011

XCEL ENERGY

THIRD QUARTER 2011 EARNINGS REPORT

Ongoing 2011 third quarter earnings per share were $0.69 compared with $0.62 in 2010.

GAAP (generally accepted accounting principles) 2011 third quarter earnings per share were $0.69 compared with $0.67 per share in 2010.

Xcel Energy expects 2011 ongoing earnings in the upper half of the guidance range of $1.65 to $1.75 per share.

Xcel Energy initiates 2012 ongoing earnings guidance of $1.75 to $1.85 per share.

MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) today reported 2011 third quarter GAAP earnings of $338 million, or $0.69 per share compared with 2010 GAAP earnings of $312 million, or $0.67 per share.

Ongoing earnings, which exclude adjustments for certain items, were $0.69 per share for the third quarter of 2011 compared with $0.62 per share in 2010. Ongoing earnings for the 2011 third quarter increased primarily due to higher electric margins as a result of warmer than normal weather across our service territories and interim rates in Minnesota and North Dakota. The higher margins were partially offset by expected increases in operating and maintenance expenses, depreciation expense and property taxes, in part from new generation plant investment.

“I am pleased to report strong third quarter earnings,” said Ben Fowke, Chairman, President and Chief Executive Officer. “As a result of higher sales due to the hot summer, we expect to deliver 2011 ongoing earnings in the upper half of our guidance range of $1.65 to $1.75 per share. In addition, our business plan remains on track, despite continued economic uncertainty and we are initiating 2012 earning guidance of $1.75 to $1.85, which is consistent with our 5 to 7 percent earnings growth objective.”

Earnings Adjusted for Certain Items (Ongoing Earnings)

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

	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
Diluted Earnings (Loss) Per Share	2011		2010		2011		2010
Ongoing(a) diluted earnings per share	$	0.69	$	0.62	$	1.43	$	1.34
COLI settlement and Medicare Part D (a)		-		0.05		-		(0.01	)
Earnings per share from continuing operations		0.69		0.67		1.43		1.33
Earnings per share from discontinued operations		-		-		-		0.01
GAAP diluted earnings per share	$	0.69	$	0.67	$	1.43	$	1.34

(a)	See Note 6.

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:	(800) 762-8779
International Dial-In:	(480) 629-9771
Conference ID:	4475769

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 2:00 p.m. CDT on Oct. 27 through 11:59 p.m. CDT on Oct. 28.

Replay Numbers
US Dial-In:	(800) 406-7325
International Dial-In:	(303) 590-3030
Access Code:	4475769#

Except for the historical statements contained in this release, the matters discussed herein, including our 2011 and 2012 full year earnings per share 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 inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc., also referred to herein as Xcel Energy Holding Co.., and its subsidiaries (collectively, Xcel Energy) to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; 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 Inc. 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 or imposed environmental compliance conditions; 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 by regulatory bodies impacting our nuclear operations, including those affecting costs, operations or the approval of requests pending before the Nuclear Regulatory Commission; financial or regulatory accounting policies imposed by regulatory bodies; availability of cost of capital; employee work force factors; 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, 2010 and Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2011.

For more information, contact:

Paul Johnson, Vice President, Investor Relations and Financial Management	(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.

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,
	2011			2010			2011				2010
Operating revenues
Electric	$	2,619,424		$	2,440,917			$	6,777,793		$	6,477,211
Natural gas		194,930			170,594				1,251,817			1,210,154
Other		17,244			17,276				56,750			56,648
Total operating revenues		2,831,598			2,628,787				8,086,360			7,744,013

Operating expenses
Electric fuel and purchased power		1,150,252			1,110,781				3,071,493			3,085,347
Cost of natural gas sold and transported		87,107			66,571				793,539			774,647
Cost of sales — other		7,154			8,848				22,100			21,244
Other operating and maintenance expenses		532,962			509,634				1,575,159			1,507,247
Conservation and demand side management program expenses		71,280			60,861				212,075			174,451
Depreciation and amortization		242,329			221,671				696,316			639,303
Taxes (other than income taxes)		89,018			81,791				278,077			244,175
Total operating expenses		2,180,102			2,060,157				6,648,759			6,446,414

Operating income		651,496			568,630				1,437,601			1,297,599

Other income, net		2,550			27,450				8,295			30,134
Equity earnings of unconsolidated subsidiaries		7,423			7,670				22,813			22,433
Allowance for funds used during construction — equity		11,840			13,464				38,690			39,750

Interest charges and financing costs
Interest charges — includes other financing costs of $6,279, $5,229, $17,724 and $15,386, respectively		148,011			144,849				438,703			430,134
Allowance for funds used during construction — debt		(6,301	)		(6,323	)			(21,575	)		(20,635	)
Total interest charges and financing costs		141,710			138,526				417,128			409,499

Income from continuing operations before income taxes		531,599			478,688				1,090,271			980,417
Income taxes		193,304			166,200				389,838			364,964
Income from continuing operations		338,295			312,488				700,433			615,453
Income (loss) from discontinued operations, net of tax		37			(182	)			230			3,747
Net income		338,332			312,306				700,663			619,200
Dividend requirements on preferred stock		1,414			1,060				3,534			3,180
Premium on redemption of preferred stock		3,260			-				3,260			-
Earnings available to common shareholders	$	333,658		$	311,246			$	693,869		$	616,020

Weighted average common shares outstanding:
Basic		485,344			460,471				484,640			459,816
Diluted.		485,894			462,019				485,152			460,722
Earnings per average common share — basic:
Income from continuing operations	$	0.69		$	0.68			$	1.43		$	1.33
Income from discontinued operations		-			-				-			0.01
Earnings per share	$	0.69		$	0.68			$	1.43		$	1.34
Earnings per average common share — diluted:
Income from continuing operations	$	0.69		$	0.67			$	1.43		$	1.33
Income from discontinued operations		-			-				-			0.01
Earnings per share	$	0.69		$	0.67			$	1.43		$	1.34

Cash dividends declared per common share	$	0.26		$	0.25			$	0.77		$	0.75

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.

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The earnings and earnings per share (EPS) of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. EPS by subsidiary is a financial measure not recognized under GAAP that is calculated by dividing the net income or loss attributable to controlling interest of each subsidiary by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use this non-GAAP financial measure to evaluate and provide details of earnings results. We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. This non-GAAP financial measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.

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	2011			2010			2011			2010
Public Service Company of Colorado (PSCo)	$	0.29		$	0.29		$	0.63		$	0.69
NSP-Minnesota		0.29			0.24			0.62			0.48
Southwestern Public Service Company (SPS)		0.10			0.08			0.17			0.16
NSP-Wisconsin		0.04			0.04			0.09			0.08
Equity earnings of unconsolidated subsidiaries		0.01			0.01			0.03			0.03
Regulated utility — continuing operations (a)		0.73			0.66			1.54			1.44
Xcel Energy Inc. and other costs		(0.04	)		(0.04	)		(0.11	)		(0.10	)
Ongoing(a) diluted earnings per share		0.69			0.62			1.43			1.34
COLI settlement and Medicare Part D (b)		-			0.05			-			(0.01	)
Earnings per share from continuing operations		0.69			0.67			1.43			1.33
Earnings per share from discontinued operations		-			-			-			0.01
GAAP diluted earnings per share	$	0.69		$	0.67		$	1.43		$	1.34

(a)	See Note 2.

(b)	See Note 6.

PSCo — PSCo earnings were flat for the third quarter and decreased $0.06 per share for the nine months ended Sept. 30, 2011. For the third quarter, higher electric margins, driven by warmer weather in July and August 2011, were offset by higher operating and maintenance (O&M) expenses, depreciation expense and property taxes. Year to date earnings decreased due to the implementation of seasonal rates in June 2010 (seasonal rates are higher in the summer months and lower throughout the other months of the year), higher O&M expenses, depreciation expense and property taxes.

NSP-Minnesota — NSP-Minnesota earnings increased $0.05 per share for the third quarter and $0.14 per share for the nine months ended Sept. 30, 2011. The increases are primarily due to interim rates, subject to refund, in Minnesota and North Dakota and conservation improvement program incentives. These factors were partially offset by higher O&M expenses, depreciation expense and property taxes.

SPS — SPS earnings increased $0.02 per share for the third quarter and $0.01 per share for the nine months ended Sept. 30, 2011. Higher electric revenues, primarily due to the Texas retail rate increase, as well as warmer weather were partially offset by higher O&M expenses, depreciation expense and property taxes.

NSP-Wisconsin — NSP-Wisconsin earnings were flat for the third quarter and increased $0.01 per share for the nine months ended Sept. 30, 2011. The implementation of new electric rates were partially offset by higher O&M expenses and depreciation expense.

The following table summarizes significant components contributing to the changes in the 2011 diluted EPS compared with the same periods in 2010, which is discussed in more detail later in the release.

Diluted Earnings (Loss) Per Share	Three Months Ended Sept. 30,			Nine Months Ended Sept. 30,
2010 GAAP diluted earnings per share	$	0.67		$	1.34
Earnings per share from discontinued operations		-			(0.01	)
2010 diluted earnings per share from continuing operations		0.67			1.33
COLI settlement and Medicare Part D (a)		(0.05	)		0.01
2010 ongoing(a) diluted earnings per share		0.62			1.34

Components of change — 2011 vs. 2010
Higher electric margins		0.18			0.42
Higher natural gas margins		0.01			0.03
Dilution from DSPP, benefit plans and the 2010 common equity issuance		(0.04	)		(0.08	)
Higher operating and maintenance expenses		(0.03	)		(0.09	)
Higher depreciation and amortization		(0.03	)		(0.08	)
Higher conservation and DSM expenses (generally offset in revenues)		(0.01	)		(0.05	)
Higher taxes (other than income taxes)		(0.01	)		(0.04	)
Other, net (including interest and premium on redemption of preferred stock)		-			(0.02	)
2011 GAAP and ongoing(a) diluted earnings per share	$	0.69		$	1.43

(a)	See Note 6.

Note 2. Regulated Utility Results — Continuing Operations

Estimated Impact of Temperature Changes on Regulated Earnings — Unseasonably hot summers or cold winters increase electric and natural gas sales while, conversely, mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per degree of temperature. Accordingly, deviations in weather from normal levels can affect Xcel Energy’s financial performance.

Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less weather sensitive.

Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction based on the time period used by the regulator in establishing estimated volumes in the rate setting process. The percentage increase (decrease) in normal and actual HDD, CDD and THI are as follows:

	Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2011 vs. Normal			2010 vs. Normal (a)			2011 vs. 2010			2011 vs. Normal			2010 vs. Normal (a)				2011 vs. 2010
HDD		(11.9	)%		(30.2	)%		26.2	%		3.8	%		(3.3	)	%		7.4	%
CDD		38.6			10.1			25.8			37.3			12.3				22.2
THI		50.3			38.8			8.3			36.0			30.5				4.3

(a)	Adjusted for the October 2010 sale of SPS electric distribution assets to the city of Lubbock, Texas.

Weather — 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,
	2011 vs. Normal		2010 vs. Normal		2011 vs. 2010		2011 vs. Normal		2010 vs. Normal			2011 vs. 2010
Retail electric	$	0.07	$	0.04	$	0.03	$	0.08	$	0.05		$	0.03
Firm natural gas		0.00		0.00		0.00		0.00		(0.01	)		0.01
Total	$	0.07	$	0.04	$	0.03	$	0.08	$	0.04		$	0.04

Sales Growth (Decline) — The following table summarizes Xcel Energy’s sales growth (decline) for actual and weather-normalized sales in 2011:

	Three Months Ended Sept. 30,
	Actual			Weather Normalized			Actual Lubbock (a)			Weather Normalized Lubbock (a)
Electric residential		2.7	%		(0.7	) %		3.8	%		0.3	%
Electric commercial and industrial		1.1			0.1			2.1			1.0
Total retail electric sales		1.7			(0.1	)		2.7			0.9
Firm natural gas sales		(1.4	)		(4.3	)		N/A			N/A

	Nine Months Ended Sept. 30,
	Actual			Weather Normalized			Actual Lubbock (a)			Weather Normalized Lubbock (a)
Electric residential		0.8	%		(0.6	) %		1.8	%		0.3	%
Electric commercial and industrial		0.6			0.2			1.5			1.1
Total retail electric sales		0.7			0.0			1.7			1.0
Firm natural gas sales		1.2			(3.0	)		N/A			N/A

(a)	Adjusted for the October 2010 sale of SPS electric distribution assets to the city of Lubbock, Texas.

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 the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin:

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Millions of Dollars)	2011			2010			2011			2010
Electric revenues	$	2,619		$	2,441		$	6,778		$	6,477
Electric fuel and purchased power		(1,150	)		(1,111	)		(3,071	)		(3,085	)
Electric margin	$	1,469		$	1,330		$	3,707		$	3,392

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

(Millions of Dollars)	Three Months Ended Sept. 30, 2011 vs. 2010			Nine Months Ended Sept. 30, 2011 vs. 2010
Retail rate increases, including seasonal rates (Minnesota interim, Wisconsin, Texas, North Dakota interim, Michigan and Colorado)	$	41		$	97
Revenue requirements for PSCo gas generation acquisition (a)		29			98
Estimated impact of weather		19			20
Conservation and DSM revenue (offset by expenses)		10			27
Firm wholesale		9			13
Conservation and DSM incentive		8			16
Transmission revenue, net of costs		5			15
Non-fuel riders		(3	)		8
Other, net (including trading and deferred fuel adjustments)		21			21
Total increase in electric margin	$	139		$	315

(a)	The increase in revenue requirements for PSCo generation reflects the acquisition of the Rocky Mountain and Blue Spruce natural gas facilities in late 2010. These revenue requirements are partially offset by higher O&M expense, depreciation expense, property taxes and financing costs.

Natural Gas — The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details natural gas revenues and margin:

	Three Months Ended Sept. 30,								Nine Months Ended Sept. 30,
(Millions of Dollars)	2011				2010				2011				2010
Natural gas revenues		$	195			$	171			$	1,252			$	1,210
Cost of natural gas sold and transported			(87	)			(67	)			(794	)			(775	)
Natural gas margin		$	108			$	104			$	458			$	435

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

(Millions of Dollars)	Three Months Ended Sept. 30, 2011 vs. 2010			Nine Months Ended Sept. 30, 2011 vs. 2010
Conservation and DSM revenue (offset by expenses)	$	1		$	12
Retail sales decrease (excluding weather impact)		(1	)		(4	)
Estimated impact of weather		-			9
Conservation and DSM incentive		-			1
Other, net		4			5
Total increase in natural gas margin	$	4		$	23

O&M Expenses — O&M expenses increased $23.3 million, or 4.6 percent, for the third quarter and $67.9 million, or 4.5 percent for the nine months ended Sept. 30, 2011 compared with the same periods in 2010. The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	Three Months Ended Sept. 30, 2011 vs. 2010		Nine Months Ended Sept. 30, 2011 vs. 2010
Higher plant generation costs	$	6	$	23
Higher labor and contract labor costs		4		18
Higher employee benefit expense		3		9
Higher facilities expense		3		3
Higher nuclear plant operation costs		3		2
Other, net		4		13
Total increase in O&M expenses	$	23	$	68

Higher plant generation costs are attributable to incremental costs associated with new generation placed in service in 2010 and a higher level of scheduled maintenance and overhaul work.

Higher labor and contract labor costs are primarily due to maintenance on our distribution facilities and the impact of annual wage increases.

Higher employee benefit costs for the nine month comparable periods are primarily due to higher pension expense.

Higher nuclear plant operation costs were largely driven by increased labor and contractors for security-related requirements.

Conservation and DSM Program Expenses — Conservation and demand side management (DSM) program expenses increased $10.4 million, or 17.1 percent for the third quarter and $37.6 million, or 21.6 percent for the nine months ended Sept. 30, 2011, compared with the same periods in 2010. The higher expense is attributable to timing and an increase in the rider rates used to recover the program expenses. Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense increased $20.7 million, or 9.3 percent for the third quarter and $57.0 million, or 8.9 percent for the nine months ended Sept. 30, 2011, compared with the same periods in 2010. The year to date increase in depreciation expense is primarily due to Comanche Unit 3 going into service in mid-May 2010, the Nobles Wind Project commencing commercial operations in late 2010, the acquisition of two gas generation facilities in December 2010 and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $7.2 million, or 8.8 percent for the third quarter and $33.9 million, or 13.9 percent for the nine months ended Sept. 30, 2011, compared with the same periods in 2010. The increase is primarily due to an increase in property taxes in Colorado and Minnesota.

Other Income, Net — Other income, net decreased $24.9 million for the third quarter and $21.8 million for the nine months ended Sept. 30, 2011, compared with the same periods in 2010. The decrease is primarily due to the corporate owned life insurance (COLI) settlement in July 2010.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased $1.6 million, or 8.3 percent for the third quarter and was flat for the nine months ended Sept. 30, 2011, compared with the same periods in 2010. The change is primarily due to lower AFUDC rates, partially offset by higher average construction work in progress due to major construction projects, including the Monticello extended power uprate and Jones Unit 3 and Unit 4, as well as SPS’ transmission projects.

Interest Charges — Interest charges increased $3.2 million, or 2.2 percent for the third quarter and $8.6 million, or 2.0 percent for the nine months ended Sept. 30, 2011, compared with the same periods in 2010. The increase is due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense for continuing operations increased $27.1 million for the third quarter of 2011, compared with the same period in 2010. The increase in income tax expense was primarily due to an increase in pretax income in 2011. The effective tax rate for continuing operations was 36.4 percent for the third quarter of 2011 compared with 34.7 percent for the same period in 2010. The higher effective tax rate for 2011 was primarily due to the establishment of a partial valuation allowance against certain state tax credit carryovers that are expected to expire. Without this adjustment, the effective tax rate for continuing operations for the third quarter of 2011 would have been 35.6 percent.

Income tax expense for continuing operations increased $24.9 million for the nine months ended Sept. 30, 2011, compared with the same period in 2010. The increase in income tax expense was primarily due to an increase in pretax income, the establishment of a partial valuation allowance in 2011 against certain state tax credit carryovers that are expected to expire, and a reversal of a valuation allowance for certain state tax credit carryovers in 2010. These were partially offset by the 2010 adjustments for a write-off of tax benefit previously recorded for Medicare Part D subsidies, an adjustment related to the COLI Tax Court proceedings, and an increase in 2011 wind production tax credits. The effective tax rate for continuing operations was 35.8 percent for the nine months ended Sept. 30, 2011 compared with 37.2 percent for the same period in 2010. The higher effective tax rate for 2010 was primarily due to the Medicare Part D, COLI, and 2010 valuation allowance. Without these adjustments, the effective tax rate for continuing operations for the first nine months of 2010 would have been 35.3 percent.

Premium on Redemption of Preferred Stock — In September 2011, Xcel Energy announced it would redeem all series of its preferred stock on Oct. 31, 2011, at an aggregate purchase price of $108 million, plus accrued dividends. As such, the redemption premium of $3.3 million and accrued dividends are reflected as reductions to earnings available to common shareholders for the three and nine months ended Sept. 30, 2011.

Note 3. Xcel Energy Capital Structure, Financing and Credit Ratings

Following is the capital structure of Xcel Energy:

(Billions of Dollars)	Sept. 30, 2011		Percentage of Total Capitalization
Current portion of long-term debt	$	0.5		3	%
Short-term debt		-		-
Long-term debt		9.5		51
Total debt		10.0		54
Preferred equity		0.1		-
Common equity		8.4		46
Total capitalization	$	18.5		100	%

Financing Plans — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund construction programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. During the third quarter, Xcel Energy Inc. and its utility subsidiaries completed the following financing:

In August 2011, PSCo issued $250 million of 30-year first mortgage bonds with a coupon of 4.75 percent.

In August 2011, SPS issued $200 million of 30-year first mortgage bonds with a coupon of 4.5 percent.

In September 2011, Xcel Energy Holding Co. issued $250 million of 30-year unsecured bonds with a coupon of 4.8 percent.

In September 2011, Xcel Energy Holding Co. announced it would redeem all series of its preferred stock on Oct. 31, 2011. The preferred stock has a par value of $105 million.

Xcel Energy Holding Co. and its utility subsidiaries’ financing plans are largely completed for 2011 with the exception of the periodic issuance and repayment of short-term debt and the expected issuance of equity through the Dividend Reinvestment and Stock Purchase Plan (DSPP) and various benefit programs, which is expected to result in the issuance of $75 million throughout 2011. Xcel Energy plans to refinance the current portion of long-term debt coming due in 2012.

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

Credit Facilities — As of Oct. 25, 2011, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:

(Millions of Dollars)	Facility		Drawn(a)		Available		Cash		Liquidity		Maturity
Xcel Energy Inc.	$	800.0	$	29.1	$	770.9	$	0.2	$	771.1	March 2015
PSCo		700.0		4.8		695.2		23.7		718.9	March 2015
NSP-Minnesota		500.0		7.1		492.9		0.2		493.1	March 2015
SPS		300.0		-		300.0		30.5		330.5	March 2015
NSP-Wisconsin		150.0		45.0		105.0		0.6		105.6	March 2015
Total	$	2,450.0	$	86.0	$	2,364.0	$	55.2	$	2,419.2

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

Credit Ratings — Access to reasonably priced capital markets is dependent in part on credit and ratings. The following ratings reflect the views of Moody’s Investors Service (Moody’s), Standard & Poor’s Rating Services (Standard & Poor’s), and Fitch Ratings (Fitch).

As of Oct. 25, 2011, the following represents the credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries:

Company	Credit Type	Moody's	Standard & Poor's	Fitch
Xcel Energy Inc.	Senior Unsecured Debt	Baa1	BBB+	BBB+
Xcel Energy Inc.	Commercial Paper	P-2	A-2	F2
NSP-Minnesota	Senior Unsecured Debt	A3	A-	A
NSP-Minnesota	Senior Secured Debt	A1	A	A+
NSP-Minnesota	Commercial Paper	P-2	A-2	F1
NSP-Wisconsin	Senior Unsecured Debt	A3	A-	A
NSP-Wisconsin	Senior Secured Debt	A1	A	A+
NSP-Wisconsin	Commercial Paper	P-2	A-2	F1
PSCo	Senior Unsecured Debt	Baa1	A-	A-
PSCo	Senior Secured Debt	A2	A	A
PSCo	Commercial Paper	P-2	A-2	F2
SPS	Senior Unsecured Debt	Baa1	A-	BBB+
SPS	Senior Secured Debt	A2	A-	A-
SPS	Commercial Paper	P-2	A-2	F2

The highest credit rating for debt is Aaa/AAA and the lowest investment grade rating is Baa3/BBB-. The ratings for commercial paper range from P-1/A-1/F-1 to P-3/A-3/F-3. A security rating is not a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Note 4. Rates and Regulation

NSP-Minnesota Electric Rate Case — In November 2010, NSP-Minnesota filed a request with the Minnesota Public Utilities Commission (MPUC) to increase annual electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million, or 1.81 percent in 2012. The rate filing was based on a 2011 forecast test year and included a requested return on equity (ROE) of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent.

The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011. The interim rates will remain in effect until the MPUC makes its final decision on the case.

In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments. The Division of Energy Resources (DOER) revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent. The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation are associated with ROE and compensation related issues.

In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million. The revisions are due to NSP-Minnesota’s decision to delay the Monticello nuclear plant extended power uprate from the fall of 2011 to the fall of 2012.

NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $27 million for the first nine months of 2011, of which $12 million was recorded during the three months ended Sept. 30 2011. The provision reflects an outcome that is consistent with the DOER position on various issues.

The MPUC decision is expected in the first quarter of 2012.

NSP-Minnesota - North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent in 2011 and a step increase of $4.2 million, or 2.6 percent in 2012. The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.

The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011. The interim rates will remain in effect until the NDPSC makes its final decision on the case.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional increase in 2012, due to the termination of the Merricourt wind project.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff. If approved, the settlement would result in a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues. To address 2011 sales coming in below test year projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.

In October 2011, the NDPSC held hearings on the settlement. An NDPSC decision is expected in the fourth quarter of 2011 with final rates expected to be implemented in the first quarter of 2012.

NSP-Minnesota - South Dakota Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the South Dakota Public Utilities Commission to increase South Dakota electric rates by $14.6 million annually, effective in 2012. The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms. The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent. NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year.

As a result of delays in the South Dakota rate case process, NSP-Minnesota anticipates requesting implementation of interim rates beginning Jan. 1, 2012 in the fourth quarter of 2011. A final decision on interim rates is expected in the first quarter of 2012.

NSP-Wisconsin 2011 Electric and Gas Rate Case — In June 2011, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) to increase electric rates approximately $29.2 million, or 5.1 percent and natural gas rates approximately $8.0 million, or 6.6 percent effective Jan. 1, 2012. The rate filing is based on a 2012 forecast test year and includes a requested ROE of 10.75 percent, an equity ratio of 52.54 percent, an electric rate base of approximately $718 million and a natural gas rate base of $84 million.

In October 2011, the PSCW Staff filed testimony and recommended an electric rate increase of $18.1 million and a natural gas rate increase of $2.9 million, based on an ROE of 10.3 percent. Rebuttal testimony supporting NSP-Wisconsin’s recommendations was filed on Oct. 21, 2011.

Evidentiary hearings are scheduled for Nov. 2, 2011. NSP-Wisconsin anticipates a PSCW decision in the fourth quarter of 2011 with new rates effective Jan. 1, 2012.

SPS New Mexico Electric Rate Case — In February 2011, SPS filed a request in New Mexico with the New Mexico Public Regulation Commission (NMPRC) seeking to increase New Mexico electric rates approximately $19.9 million. The rate filing was based on a 2011 test year adjusted for known and measurable changes for 2012, a requested ROE of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent.

In September 2011, the parties filed an unopposed black box settlement to resolve all issues in the case. If the settlement is approved by the NMPRC, base rates will increase by $13.5 million. SPS has agreed not to file another base rate case until Dec. 3, 2012 with new final rates from the result of such case not going into effect until Jan. 1, 2014 (Settlement Period), provided however, that SPS can request to implement interim rates if the NMPRC standard for interim rates is met. During the Settlement Period, rates are to remain fixed aside from the continued operation of the fuel adjustment clause and certain exceptions for energy efficiency, a rider for an approved renewable portfolio standard regulatory asset, and actual costs incurred for environmental regulations with an effective date after Dec. 31, 2010.

In October 2011, the NMPRC held hearings on the settlement. A decision by the NMPRC is expected by year-end and final rates are expected to be implemented effective Jan. 1, 2012.

PSCo Wholesale Electric Rate Case — In February 2011, PSCo filed with the Federal Energy Regulatory Commission to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent. The formula rate would be estimated each year for the following year and then would be trued up to actual costs after the conclusion of the calendar year. A decision is expected in the first quarter of 2012.

PSCo 2010 Gas Rate Case — In December 2010, PSCo filed a request with the Colorado Public Utilities Commission

(CPUC) to increase Colorado retail gas rates by $27.5 million on an annual basis. In March 2011, PSCo revised its requested rate increase to $25.6 million. The revised request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.1 percent. PSCo proposed recovering $23.2 million of test year capital and O&M expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006. PSCo also proposed removing the earnings on gas in underground storage from base rates.

In August 2011, the CPUC approved a comprehensive settlement that PSCo reached with CPUC Staff and the Colorado Office of Consumer Counsel to increase rates by $12.8 million, to institute rider recovery of future pipeline integrity costs, and to remove gas in underground storage from base rates and recover those costs in the Gas Cost Adjustment (GCA) rider. The GCA recovery of the return on gas in underground storage is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs. Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent.

New base rates and the GCA recovery went into effect in September 2011. The rider for pipeline integrity costs is expected to go into effect on Jan. 1, 2012 and is expected to recover an estimated $31.5 million of incremental revenue in 2012.

Note 5. Xcel Energy Ongoing Earnings Guidance

Xcel Energy’s 2011 ongoing earnings guidance is $1.65 to $1.75 per share. Xcel Energy expects 2011 ongoing earnings to be in the upper half of the guidance range. Key assumptions related to ongoing earnings are detailed below:

Normal weather patterns are experienced for the remainder of the year.

Weather-adjusted retail electric utility sales, adjusted for the sale of the Lubbock distribution assets, are projected to grow approximately 1 percent.

Weather-adjusted retail firm natural gas sales are projected to decline approximately 3 percent.

Constructive outcomes in all rate case and regulatory proceedings.

Rider revenue recovery is projected to be relatively flat.

O&M expenses are projected to increase approximately 4.5 percent.

Depreciation expense is projected to increase approximately $60 million to $70 million.

Interest expense (net of AFUDC — debt) is projected to increase approximately $10 million to $15 million.

AFUDC — equity is projected to be relatively flat.

The effective tax rate is projected to be approximately 35 percent to 36 percent.

Average common stock and equivalents are projected to be approximately 486 million shares.

Xcel Energy’s 2012 ongoing earnings guidance is $1.75 to $1.85 per share. Key assumptions related to ongoing earnings are detailed below:

Constructive outcomes in all rate case and regulatory proceedings.

Normal weather patterns are experienced for the year.

Weather-adjusted retail electric utility sales are projected to grow 0.5 to 1.0 percent.

Weather-adjusted retail firm natural gas sales are projected to grow up to 1.0 percent.

Rider revenue recovery is projected to increase approximately $50 million to $55 million over 2011 projected levels.

O&M expenses are projected to increase approximately 3.0 to 4.0 percent over 2011 projected levels.

Depreciation expense is projected to increase $70 million to $80 million over 2011 projected levels.

Interest expense (net of AFUDC — debt) is projected to be relatively flat.

AFUDC — equity is projected to increase approximately $25 million to $30 million over 2011 projected levels.

The effective tax rate is projected to be approximately 34 percent to 36 percent.

Average common stock and equivalents are projected to be approximately 488 million shares.

Note 6. Non-GAAP Reconciliation

Xcel Energy’s management believes that ongoing earnings provide a meaningful comparison of earnings results and is 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 Sept. 30,					Nine Months Ended Sept. 30,
(Thousands of Dollars)	2011		2010			2011		2010
Ongoing earnings	$	338,252	$	287,002		$	700,348	$	618,836
COLI settlement and Medicare Part D		43		25,486			85		(3,383	)
Total continuing operations		338,295		312,488			700,433		615,453
Income (loss) from discontinued operations		37		(182	)		230		3,747
GAAP earnings	$	338,332	$	312,306		$	700,663	$	619,200

Ongoing earnings exclude the impact of Internal Revenue Service (IRS) tax and interest adjustments related to the COLI program, the write-off of previously recognized tax benefits relating to Medicare Part D subsidies due to the enacted Patient Protection and Affordable Care Act and a settlement related to the previously discontinued COLI program.

Impact of the Patient Protection and Affordable Care Act — Medicare Part D — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, Xcel Energy is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment. Xcel Energy expensed approximately $17 million, or $0.04 per share, of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. Xcel Energy does not expect the $17 million of additional tax expense to recur in future periods.

COLI — During 2007, Xcel Energy reached a settlement with the IRS related to a dispute associated with its COLI program. These COLI policies were owned and managed by P.S.R. Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. As a follow on to the 2007 IRS COLI settlement, as part of the Tax Court proceedings, during the first quarter of 2010, Xcel Energy and the IRS reached an agreement in principle after a comprehensive financial reconciliation of Xcel Energy's statements of account, dating back to tax year 1993. Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $10 million (including $7.7 million tax expense and $2.3 million interest expense, net of tax), or $0.02 per share during the first quarter of 2010. During the third quarter of 2010, Xcel Energy and the IRS came to final agreement on the applicable interest netting computations related to these tax years. Accordingly, PSRI recorded a reduction to expense of $0.6 million, net of tax, during the third quarter of 2010. The Tax Court proceedings were dismissed in December 2010 and January 2011.

In July 2010, Xcel Energy Inc., PSCo and PSRI entered into a settlement agreement with Provident Life & Accident Insurance Company (Provident) related to all claims asserted by Xcel Energy Inc., PSCo and PSRI against Provident in a lawsuit associated with the discontinued COLI program. Under the terms of the settlement, Xcel Energy Inc., PSCo and PSRI were paid $25 million by Provident and Reassure America Life Insurance Company resulting in approximately $0.05 of non-recurring earnings per share in the third quarter of 2010. The $25 million proceeds were not subject to income taxes.

XCEL ENERGY INC. AND SUBSIDIARIES

EARNINGS RELEASE SUMMARY (UNAUDITED)

(amounts in thousands, except earnings per share)

	Three Months Ended Sept. 30,
	2011			2010
Operating revenues:
Electric and natural gas revenues	$	2,814,354		$	2,611,511
Other		17,244			17,276
Total operating revenues		2,831,598			2,628,787

Income from continuing operations		338,295			312,488
Income (loss) from discontinued operations		37			(182	)
Net income	$	338,332		$	312,306

Earnings available to common shareholders	$	333,658		$	311,246
Weighted average diluted common shares outstanding		485,894			462,019

Components of Earnings per Share — Diluted
Regulated utility — continuing operations	$	0.73		$	0.66
Xcel Energy Inc. and other costs		(0.04	)		(0.04	)
Ongoing(a) diluted earnings per share		0.69			0.62
COLI settlement and Medicare Part D (a)		-			0.05
Earnings per share from continuing operations		0.69			0.67
Earnings per share from discontinued operations		-			-
GAAP diluted earnings per share	$	0.69		$	0.67

	Nine Months Ended Sept. 30,
	2011			2010
Operating revenues:
Electric and natural gas revenues	$	8,029,610		$	7,687,365
Other		56,750			56,648
Total operating revenues		8,086,360			7,744,013

Income from continuing operations		700,433			615,453
Income from discontinued operations		230			3,747
Net income	$	700,663		$	619,200

Earnings available to common shareholders	$	693,869		$	616,020
Weighted average diluted common shares outstanding		485,152			460,722

Components of Earnings per Share — Diluted
Regulated utility — continuing operations	$	1.54		$	1.44
Xcel Energy Inc. and other costs		(0.11	)		(0.10	)
Ongoing(a) diluted earnings per share		1.43			1.34
COLI settlement and Medicare Part D (a)		-			(0.01	)
Earnings per share from continuing operations		1.43			1.33
Earnings per share from discontinued operations		-			0.01
GAAP diluted earnings per share	$	1.43		$	1.34

Book value per share	$	17.39		$	16.53

(a)	See Note 6.

Attached files

PUBLIC SERVICE CO OF COLORADO Reports

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