News Details

• Ongoing earnings per share were $1.62 in 2010, compared with $1.50 in 2009, achieving the upper half of Xcel Energy’s guidance range.
• GAAP (generally accepted accounting principles) 2010 earnings were $756 million, or $1.62 per share, compared with $681 million, or $1.48 per share in 2009.
• Xcel Energy reaffirms 2011 ongoing earnings guidance of $1.65 to $1.75 per share.

MINNEAPOLIS--(BUSINESS WIRE)-- Xcel Energy Inc. (NYSE: XEL) today reported 2010 GAAP earnings of $756 million, or $1.62 per share compared with 2009 GAAP earnings of $681 million, or $1.48 per share.

Ongoing earnings for 2010, which exclude adjustments for certain items, were $1.62 per share compared with $1.50 per share in 2009. Higher 2010 ongoing earnings were primarily due to improved electric margins as a result of new rates in various jurisdictions and warmer summer temperatures, which were partially offset by higher operating and maintenance expenses and property taxes.

“We had another very successful year in 2010,” said Richard C. Kelly, chairman and chief executive officer. “We delivered earnings in the upper half of our guidance range. This represents the sixth consecutive year in which we have met or exceeded our earnings guidance. During 2010, we maintained a high level of customer satisfaction and successfully met or exceeded our energy efficiency and conservation program targets. Additionally, we completed the acquisition of two natural gas power plants in Colorado, our Comanche Unit 3 and Nobles wind farm commenced commercial operation, we began construction on the CapX2020 transmission project and we received commission approval of our Clean Air Clean Jobs plan, which is designed to reduce emissions in Colorado. Finally, we are reaffirming our 2011 ongoing earnings guidance of $1.65 to $1.75 per share.”

Earnings Adjusted for Certain Items (Ongoing Earnings)

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

At 10 a.m. CST 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.

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 1:00 p.m. CST on Jan. 27 through 11:59 p.m. CST on Jan. 28.

Except for the historical statements contained in this release, the matters discussed herein, including our 2011 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 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 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 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, 2009 and on Xcel Energy’s Quarterly Reports on Form 10-Q for the quarters ended March 31, and June 30, and Sept. 30, 2010.

This information is not given in connection with any

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

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:

PSCo — PSCo earnings decreased by $0.04 per share for the fourth quarter and increased by $0.14 per share for 2010. The decrease for the fourth quarter reflects the impact of lower seasonal rates that were effective Oct. 1, 2010, offsetting, to a certain degree, higher summer seasonal rates that were effective June 1, 2010. Seasonal rates are designed to be revenue neutral on an annual basis. Therefore, the quarterly pattern of revenue collection is different than in the past, as seasonal rates are higher in the summer months and lower throughout the latter part of the year. The annual increase is due to higher electric margin resulting from the full effect of two general rate increases, and warmer temperatures, which increased electric sales. The rate increases reflect the significant capital investments that PSCo has made in its utility operations. In addition, PSCo’s electric operations substantially under-earned its authorized return in 2009. The higher electric margin was partially offset by higher operating and maintenance (O&M) expenses, higher property tax expense and depreciation expense.

NSP-Minnesota — NSP-Minnesota earnings decreased by $0.04 per share for both the fourth quarter and 2010. The annual decrease is primarily due to higher O&M expenses, property taxes and depreciation expense partially offset by the positive impact of warmer temperatures, higher earned incentives on energy efficiency and conservation programs and modest normalized sales growth.

SPS — SPS earnings were flat for the fourth quarter and increased by $0.02 per share in 2010. The annual increase is primarily due to electric sales growth, particularly in the commercial and industrial customer class, the reversal of previously established fuel reserves following the regulatory approval of certain settlement agreements and lower interest expense, which was partially offset by higher O&M expenses.

NSP-Wisconsin — NSP-Wisconsin earnings were flat during the fourth quarter and decreased by $0.01 per share for 2010. The annual decrease is primarily due to fuel recovery and higher O&M expenses, partially offset by warmer temperatures which, increased electric sales, as well as new electric rates that were effective in January 2010.

Equity Earnings of Unconsolidated Subsidiaries - The annual increase is primarily related to earnings from the equity investment in WYCO Development LLC, related to a natural gas storage facility that began operating in mid-2009.

The following table summarizes significant components contributing to the changes in the 2010 diluted earnings per share compared with the same periods in 2009, which are discussed in more detail later in the release.

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:

The following table summarizes the estimated impact on earnings per share of temperature variations compared with sales under normal weather conditions:

Sales Growth (Decline) — The following table summarizes Xcel Energy’s sales growth (decline) for actual and weather-normalized sales for 2010 as compared with the same periods in 2009.

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 tables detail the electric revenues and margin:

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

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 tables detail natural gas revenues and margin:

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

O&M Expenses — O&M expenses increased by approximately $52.7 million, or 10.6 percent, for the fourth quarter and by $149.2 million, or 7.8 percent for 2010, compared with 2009. The following table summarizes the changes in other O&M expenses:

• Higher plant generation costs are primarily attributable to the timing of planned maintenance and overhaul work as well as incremental operating costs associated with new generation facilities placed in service in 2010.
• Higher contract labor is primarily related to maintenance on our distribution facilities.
• Higher nuclear plant operation costs are mainly due to increase labor and security expenses.
• Higher labor costs are primarily due to higher overtime for storm restoration work and a shift in labor resources from capital to O&M projects.
• Higher nuclear outage costs are due to the timing and higher cost of nuclear refueling outages.
• Lower employee benefit costs for the quarter are primarily related to the timing of performance based incentive compensation. Higher employee benefit costs for the year are primarily due to increased pension costs partially offset by lower health care costs.

Conservation and DSM Program Expenses — Conservation and DSM program expenses increased by approximately $17.1 million, or 35.3 percent, for the fourth quarter and by $57.7 million, or 31.7 percent, for 2010 compared with 2009. The higher expense is attributable to the continued expansion of programs and regulatory commitments. Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expenses increased by approximately $10.8 million, or 5.2 percent, for the fourth quarter and by $40.8 million, or 5.0 percent, for 2010 compared with 2009. The change in depreciation expense is primarily due to Comanche Unit 3 going into service and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $10.3 million, or 13.3 percent, for the fourth quarter and by $25.5 million, or 8.3 percent, for 2010 compared with 2009. The increase is primarily due to an increase in property taxes in Colorado and Minnesota.

Other Income (Expense), Net — Other income (expense), net increased by $21.4 million for 2010 compared with 2009. The 2010 increase is primarily due to the corporate owned life insurance (COLI) settlement in July 2010.

Equity Earnings of Unconsolidated Subsidiaries — Equity earnings of unconsolidated subsidiaries increased by $5.3 million for 2010 compared with 2009. The annual increase is primarily related to earnings from the equity investment in WYCO Development LLC, related to a natural gas storage facility that began operating in mid-2009.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased by approximately $5.8 million for the fourth quarter and by $30.7 million for 2010 compared with 2009. The decrease was partially due to Comanche Unit 3 going into service in May 2010 as well as lower AFUDC rates.

Interest Charges — Interest charges increased by approximately $6.0 million, or 4.2 percent, for the fourth quarter and by $15.6 million, or 2.8 percent, for 2010 compared with 2009. 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 decreased by $19.1 million for the fourth quarter of 2010, compared with the same period in 2009. The decrease in income tax expense was primarily due to a decrease in pretax income. The effective tax rate for continuing operations was 34.4 percent for the fourth quarter of 2010, compared with 34.7 percent for the same period in 2009.

Income tax expense for continuing operations increased by $65.3 million for 2010, compared with 2009. The increase in income tax expense was primarily due to an increase in pretax income, one time adjustments for a write-off of tax benefit previously recorded for Medicare Part D subsidies and an adjustment related to the COLI Tax Court proceedings. This was partially offset by a reversal of a valuation allowance for certain state tax credit carryovers. The effective tax rate for continuing operations was 36.7 percent for 2010, compared with 35.1 percent for the same period in 2009. The higher effective tax rate for 2010 was primarily due to the adjustments referenced above. The effective tax rate for ongoing earnings for 2010 was 35.3 percent.

Note 3.PSCo Acquires Generation Assets

In December 2010, PSCo completed the purchase of the Blue Spruce Energy Center and Rocky Mountain Energy Center from Calpine Development Holdings, Inc. and Riverside Energy Center LLC for $739 million plus an additional $3 million for working capital adjustments. The Blue Spruce Energy Center is a 310 MW simple cycle natural gas-fired power plant that began commercial operations in 2003. The Rocky Mountain Energy Center is a 652 MW combined-cycle natural gas-fired power plant that began commercial operations in 2004. Both power plants previously provided energy and capacity to PSCo under purchased power agreements, which were set to expire in 2013 and 2014, respectively.

Note 4.Xcel Energy Capital Structure, Financing and Credit Ratings

Following is the capital structure of Xcel Energy:

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. In addition to the periodic issuance and repayment of short-term debt, Xcel Energy and its utility subsidiaries’ financing plans are as follows:

• NSP-Minnesota may issue up to $300 million of first mortgage bonds during the second half of 2011.
• PSCo may issue approximately $250 million of first mortgage bonds during the second half of 2011.
• SPS may issue approximately $150 million of senior unsecured notes during the second half of 2011.
• Xcel Energy also anticipates issuing approximately $75 million of equity through the Dividend Reinvestment Program and various benefit programs in 2011.

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

Equity Forward Agreements — In August 2010, Xcel Energy entered into equity forward agreements (Forward Agreements) in connection with a public offering of 21.85 million shares of Xcel Energy common stock. Under the Forward Agreements, Xcel Energy agreed to issue to the banking counterparty 21.85 million shares of its common stock.

On Nov. 29, 2010, Xcel Energy settled the Forward Agreements by physically delivering 21.85 million shares of common equity and receiving cash proceeds of $449.8 million. The price used to determine cash proceeds was calculated based on the August 2010 public offering price of Xcel Energy’s common stock, adjusted for underwriting fees, as well as a daily adjustment based on the federal funds rate less a spread of 0.50 percent, and a decrease to reflect the dividend paid on Xcel Energy’s common stock in October 2010.

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

Xcel Energy plans to syndicate new credit agreements at the Holding Company, NSP-Minnesota, PSCo, SPS and NSP-Wisconsin during the first quarter of 2011. The total anticipated size of the new credit facilities will be approximately $2.45 billion.

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 Jan. 25, 2011, the following represents the credit ratings assigned to various Xcel Energy companies:

Moody’s highest credit rating for debt is Aaa and lowest investment grade rating is Baa3. Both Standard & Poor’s and Fitch’s highest credit rating for debt are AAA and lowest investment grade rating is BBB-. Moody’s prime ratings for commercial paper range from P-1 to P-3. Standard & Poor’s ratings for commercial paper range from A-1 to A-3. Fitch’s ratings for commercial paper range from F1 to F3. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Capital Expenditures — The estimated capital expenditure programs of Xcel Energy and its subsidiaries for the years 2011 through 2015 are shown in the tables below.

The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions and approvals, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of restructuring requirements, compliance with future environmental requirements and Renewable Portfolio Standards’ to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Note 5.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. The rate filing is 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.

NSP-Minnesota requested an additional increase of $48.3 million or 1.81 percent effective Jan. 1, 2012, to address certain known and measurable cost increases in 2012. Additionally, NSP-Minnesota seeks to transfer approximately $158 million already collected from ratepayers through riders into base rates at the conclusion of this case with implementation of final rates.

The MPUC approved an interim rate increase of $123 million, effective Jan. 2, 2011. The interim rates will remain in effect until the MPUC makes its final decision on the case. An MPUC decision is anticipated in the fourth quarter of 2011. The following procedural schedule has been established:

• Intervenor direct testimony due April 5, 2011;
• Rebuttal testimony due May 4, 2011;
• Surrebuttal testimony due May 26, 2011;
• Evidentiary hearings due June 1-8, 2011;
• Initial brief due July 29, 2011;
• Reply Brief & Findings due Aug. 19, 2011;
• Administrative law judge (ALJ) recommendations Sept. 26, 2011; and
• MPUC Order due Dec. 1, 2011.

NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $16.2 million for 2010, based on an ROE of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million. In December 2009, the MPUC approved an interim rate increase of $11.1 million, subject to refund. Interim rates went into effect on Jan. 11, 2010.

During 2010, NSP-Minnesota revised its request to an increase of $10.0 million based on an ROE of 10.6 percent. In November 2010, the MPUC authorized a rate increase of approximately $7 million, based on an ROE of 10.0 percent.

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. 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. NSP-Minnesota requested an additional increase of $4.2 million, or 2.6 percent, effective Jan. 1, 2012, to address certain known and measurable cost increases in 2012.

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

NSP-Wisconsin - 2010 Electric Rate Case Reopener — In August 2010, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) to reopen the 2010 rate case and increase retail electric rates for 2011 by $29.1 million, or 5.4 percent, based on a forecast 2011 test year. On Jan. 12, 2011, the PSCW issued its final decision in the case, approving an increase of $21.1 million or 3.9 percent. The new rates went into effect on Jan. 15, 2011.

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, effective in the summer of 2011. The request was based on a 2011 forecast test year, a 10.90 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.10 percent.

The increase in natural gas rates is to recover capital and O&M expenses associated with several pipeline integrity programs, plus amortization of similar costs that have been deferred since the last rate case in 2006 and increased O&M expenses related to pension and benefit expenses and property taxes. PSCo also proposed that beginning in 2012, it be allowed to recover certain compliance and aging infrastructure costs through a pipeline integrity rider.

PSCo - Colorado Clean Air-Clean Jobs Act — The Colorado Clean Air-Clean Jobs Act (CACJA) was signed into law in April 2010. The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of nitrogen oxide (NOx) by at least 70 to 80 percent or greater from 2008 levels from the coal-fired generation identified in the plan. The plan was required to consider both current and reasonably foreseeable Clean Air Act requirements and allows PSCo to propose emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by Dec. 31, 2017. The legislation further encourages PSCo to submit long-term gas contracts to the CPUC for approval. The CACJA permits the CPUC to consider interim rate increases after Jan. 1, 2012, while the rate filing is pending and allows for multi-year rate plans.

In December 2010, the CPUC approved the following:

• Shutdown Cherokee Units 1 and 2 in 2011 and Cherokee Unit 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);
• Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017;
• Shutdown Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (352 MW) in 2013 to natural gas;
• Shutdown Valmont Unit 5 (186 MW) in 2017;
• Install selective-catalytic reduction (SCR) for controlling NO_X and a scrubber for controlling sulfur dioxide on Pawnee Station in 2014;
• Install SCR on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and
• Convert Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.

The CPUC provided for recovery on construction work in progress in rate base in each rate case and deferred accounting of accelerated depreciation costs. PSCo needs to make applications for detailed cost review before commencing each phase of the plan. The CPUC also encouraged PSCo to hold stakeholder meetings to discuss issues around a multi-year rate plan. On Jan. 7, 2011, the Colorado Air Quality Control Commission unanimously approved incorporation of the CACJA plan into Colorado's regional haze state implementation plan (SIP). The Colorado state legislature must approve the SIP, which will contain provisions of the CACJA approved by the CPUC. The legislature may hold hearings on the SIP or offer a bill to revise it. Upon legislative approval, the SIP will be sent to the governor for signature by Feb. 15, 2011. The total investment associated with the adopted plan is approximately $1.0 billion over the next seven years. The rate impact of the proposed plan is expected to increase future bills on average by 2 percent annually.

PSCo 2010 Electric Rate Case — In December 2009, the CPUC approved a rate increase of approximately $128.3 million; however, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo’s proposal to phase in the approved electric rate increase to reflect the actual cost of service. In the first quarter of 2011, the CPUC reconsidered several matters at PSCo request and increased that amount by $2.2 million.

Under the plan, the following increases have been implemented:

• A rate increase of $67 million was implemented on Jan. 1, 2010, due to the delay of the in-service date of Comanche Unit 3.
• In May 2010, base rates were increased to recover $125 million annually, when Comanche Unit 3 went into service.
• Base rates were increased to recover approximately $130 million annually on Jan. 1, 2011, to reflect 2011 property taxes.

A second phase of the rate case addressed changes to rate design. The new rates, approved by the CPUC, went into effect on June 1, 2010. In this phase of the proceeding, the CPUC approved tiered summer rates for residential customers and seasonally differentiated rates for other customer classes, which will impact the timing of revenue collection, as compared to the previous rate design, depending on customer response. Fourth quarter electric revenues and margin for 2010 were negatively impacted by approximately $22 million, while year-to-date electric revenues and margin was positively impacted by approximately $31 million, related to the implementation of such rate design and seasonal rates. Seasonal rates are designed to be revenue neutral on an annual basis. However, the quarterly pattern of revenue collection is expected to be different than in the past as seasonal rates are higher in the summer months and lower throughout the remainder of the year.

SPS - Texas Electric Rate Case — In May 2010, SPS filed an electric rate case in Texas seeking an annual base rate increase of approximately $71.5 million inclusive of franchise fees. On a net basis, the request seeks to increase customer bills by approximately $53.4 million or 7 percent. The rate filing is based on a 2009 test year adjusted for known and measurable changes, a requested ROE of 11.35 percent, an electric rate base of $1.031 billion and an equity ratio of 51.0 percent. The filing with the Public Utility Commission of Texas also includes a request to reconcile SPS’ fuel and purchased power costs for calendar years 2008 and 2009. As of Dec. 31, 2009, SPS had a fuel cost under-recovery of approximately $3.3 million.

In the fall of 2010, SPS filed an update to the cost of service to reflect the impact on Texas retail rates, primarily resulting from its sale of Lubbock facilities. The total request was reduced to approximately $63.7 million and the net request $47.6 million.

The parties to the case have agreed that the effective date of implementation of SPS’ new rates is expected to be Feb. 16, 2011. This will be accomplished either by establishing interim rates effective on Feb. 16, 2011, or through a surcharge retroactive to this date. While there are still many details to be finalized, SPS and the various parties have progressed on settlement negotiations and the ALJ abated the current procedural schedule. Under the ALJ’s order, the parties have a deadline of Feb. 11, 2011, to file a settlement or a status update.

Note 6.Xcel Energy Ongoing Earnings Guidance

Xcel Energy’s 2011 ongoing earnings guidance is $1.65 to $1.75 per share. Key assumptions related to ongoing earnings are detailed below:

• Normal weather patterns are experienced for the year.
• Weather-adjusted retail electric utility sales, adjusted for the sale of the Lubbock distribution assets, are projected to grow approximately 1.0 to 1.3 percent.
• Weather-adjusted retail firm natural gas sales are projected to be relatively flat.
• Constructive outcomes in all rate case and regulatory proceedings.
• Rider revenue recovery is projected to increase approximately $35 million.
• O&M expenses are projected to increase approximately 4 percent.
• Depreciation expense is projected to increase $55 million to $65 million.
• Interest expense is projected to increase approximately $15 million to $25 million.
• AFUDC — equity is projected to be relatively flat.
• The effective tax rate is projected to be approximately 34 percent to 36 percent.
• Average common stock and equivalents are projected to be approximately 485 million shares.

Note 7.Non-GAAP Reconciliation

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

COLI Settlement

In July 2010, Xcel Energy, PSCo and P.S.R. Investments Inc. (PSRI) entered into a settlement agreement with Provident Life & Accident Insurance Company (Provident) related to all claims asserted by Xcel Energy, PSCo and PSRI against Provident in a lawsuit associated with the discontinued COLI program. Under the terms of the settlement, Xcel Energy, 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 are not subject to income taxes.

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.

PSRI

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 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. 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.

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:

^(a) See Note 7

Source: Xcel Energy

Xcel Energy

Paul Johnson, 612-215-4535

Managing Director, Investor Relations and Assistant Treasurer

or

Jack Nielsen, 612-215-4559

Director, Investor Relations

or

Cindy Hoffman, 612-215-4536

Senior Investor Relations Analyst

or

For news media inquiries only:

Xcel Energy media relations, 612-215-5300

Xcel Energy Internet address:

www.xcelenergy.com