August 19, 2010

Ms. Jennifer Thompson

Branch Chief

United States Securities and Exchange Commission

Division of Corporation Finance

Washington, D.C. 20549

Re: Xcel Energy Inc., File No. 1-03034

Form 10-K for Fiscal Year Ended December 31, 2009

Filed February 26, 2010

Northern States Power Company (Minnesota), File No. 1-31387

Northern States Power Company (Wisconsin), File No. 1-03140

Public Service Company of Colorado, File No. 1-03280

Southwestern Public Service Company, File No. 1-03789

Form 10-K for the Fiscal Year Ended December 31, 2009

Filed March 1, 2010

Dear Ms. Thompson:

Reference is made to your letter to Mr. David M. Sparby, dated Aug. 3, 2010, in which you transmitted comments of the Staff of the Division of Corporation Finance with respect to the above filings (the “Staff Comment Letter”). This letter is submitted on behalf of Xcel Energy Inc. (“Xcel Energy”), Northern States Power Co. (Minnesota) (“NSP-Minnesota”), Northern States Power Co. (Wisconsin) (“NSP-Wisconsin”) Public Service Company of Colorado (“PSCo”) and Southwestern Public Service Company (“SPS”) (collectively, “the Companies”) in response to the Staff Comment Letter. To assist you in your review, we have repeated the full text of the Staff’s comments in italics in this letter, and our responses follow immediately. Where our responses include proposed revisions to disclosures, they are based on the disclosures in the Companies’ Forms 10-K for the year ended December 31, 2009 or Forms 10-Q for the period ending June 30, 2010.

Form 10-K for the Fiscal Year Ended December 31, 2009

General

1. Please note that the following comments, unless otherwise specifically noted, address accounting practices, presentation and disclosure matters of Xcel Energy Inc. and subsidiaries on a consolidated basis. In our interest to reduce the volume of comments, we have not addressed each subsidiary with a separate comment if applicable to their facts and circumstances. Please note that if you agree to a revision, we would also expect a concurrent change be made in the subsidiary level financial statements to the extent material. Please confirm to us your agreement with this objective.

Response:

The Companies agree with the objective, as described above. Changes made to the Xcel Energy disclosures will, to the extent applicable and material, also be made to the subsidiary disclosures.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 48

Statement of Operations Analysis - Continuing Operations, page 56

2. We note your references to “normal weather conditions” and “weather-normalized energy sales” in your discussions of estimated impact of temperature changes on regulated earnings and in sales growth (decline). Please define what you consider to be normal weather conditions and consider providing data on the actual weather conditions for each year under comparison. Given that weather has a significant effect on your operations, we believe this will provide useful information to investors and assist them in understanding the impact that weather has on your operations.

Response:

We define and determine normal weather conditions using 20-year or 30-year daily average weather in our primary service territories, utilizing data published by the National Oceanic and Atmospheric Administration (NOAA). The NOAA computes monthly normal heating degree days (HDD) and cooling degree days (CDD) for various locations in the United States. HDDs and CDDs represent the number of degrees difference between ambient temperature and a base level temperature. HDDs and CDDs are designed to measure the weather impacts which drive the energy use of a home for heating and cooling. The base level temperature is supposed to approximate the outside temperature at which a person inside a home would need to turn on the heating or air conditioning system, in order to remain comfortable inside. This base level temperature is 65° Fahrenheit. In Xcel Energy’s service territories located in the north central U.S. where both hot weather and humidity can impact energy consumption, primarily for air conditioning load, a temperature humidity index (THI) is used in place of CDD, which adds a humidity factor to CDDs.

For the winter and portions of the fall and spring seasons, we use HDD information, with one heating degree-day based on each degree of temperature below 65° Fahrenheit. For the summer and portions of the spring and fall seasons, we use either cooling degree day CDD information or a THI. One CDD is based on each degree of temperature above 65° Fahrenheit and THI is based on CDDs plus a humidity factor.

Using information for June 30, 2010 as an example, disclosure comparable to the following will be added, to the extent applicable, in future filings of Quarterly and Annual Reports on Form 10-Q and 10-K:

Weather — 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 increase (decrease) in normal and actual HDD, CDD and THI for the three and six months ended June 30, 2010 and 2009 are provided in the following table:

	Three Months Ended June 30,						Six Months Ended June 30,
	2010 vs.		2009 vs.		2010 vs.		2010 vs.		2009 vs.		2010 vs.
	Normal		Normal		2009		Normal		Normal		2009
HDD	17.3	%	1.1	%	16.4	%	3.2	%	0.7	%	2.5	%
CDD	17.5		(2.4	)	20.1		17.5		2.0		19.9
THI	4.8		(11.7	)	18.7		4.8		(11.7	)	18.7

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,
	2010 vs.			2009 vs.			2010 vs.			2010 vs.			2009 vs.			2010 vs.
	Normal			Normal			2009			Normal			Normal			2009
Retail electric	$	0.01		$	(0.01	)	$	0.02		$	0.01		$	(0.01	)	$	0.02
Firm natural gas	(0.01		)	0.00			(0.01		)	(0.01		)	(0.01		)	0.00
Total	$	0.00		$	(0.01	)	$	0.01		$	0.00		$	(0.02	)	$	0.02

While there were regional weather variations across our service territory, the earnings per share impact was diminished due to different electric per unit contributions to margins from sales among these territories.

Financial Statements and Supplementary Data, page 80

Notes to Consolidated Financial Statements, page 89

1. Summary of Significant Accounting Policies, page 89

General

3. We note references throughout your filing of your conservation and demand side management programs. Please tell us the nature of these programs, how you account for them, how they are presented in your financial statements and the basis for your accounting and presentation.

Response:

Nature of Programs

Our operating companies have established Demand Side Management (DSM) or Conservation Improvement Programs (CIP) in many of their retail jurisdictions. Overall, the programs are designed to encourage the operating companies and their retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas/electric system. This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers.

A program is designated as DSM or CIP, depending upon the state jurisdiction, but in all cases is intended to achieve overall efficiency and conservation of energy. Examples of residential energy conservation programs and services include, but are not limited to:

· Compact fluorescent (CFL) bulbs — Energy efficient CFL bulbs offered at wholesale prices in retail stores and online

· Cooling and heating rebates — Rebates for energy efficient heating and cooling equipment, such as furnaces, heat pumps, programmable thermostats, attic and wall insulation, duct sealing and weather stripping

· Saver switch — Monthly summer discounts for cycling air conditioner units on hot summer days

· Water heater rebates — Rebates offered for energy-efficient usage during off peak hours

Examples of business energy conservation programs and services include, but are not limited to:

· Boiler efficiency/furnace efficiency/heating efficiency — Rebates for replacing or upgrading natural gas-fired, hot-water boilers, high efficiency furnaces and heating systems

· Electric rate savings — Reduced electric rates for reducing demand for electricity to a predetermined level during control periods

· Lighting efficiency/redesign — Study funding and rebates for energy-savings lighting analysis and installations

Typically, DSM/CIP programs are designed and administered by the respective operating company and are subject to state public utility regulatory oversight. In most cases the operating company proposes the level of expenditures based upon criteria established by its respective regulatory commission. Prior to receiving the respective commission’s approval, the operating company provides a description of the DSM/CIP program, the goals of the program, and the types of expenditures that will be required to meet the goals of the DSM/CIP program.

The planned expenditure levels are typically approved by the applicable state commission, often under a multi-year plan. These plans often contain an efficiency target for the spending level as well as other criteria related to total expenditures, types of allowable costs, and the types of programs. In most cases, the programs are targeted to various customer segments (as noted above) such as residential customers, low income customers, commercial and industrial customers, pilot or experimental programs and/or educational programs. The programs address cost recovery for all elements of the program, including program design, program administration, customer incentives and discounts, customer education, advertising and promotion, cost of equipment and labor for participants and utilities.

Over the years, the state-approved cost recovery has evolved and changed. In Xcel Energy’s largest retail jurisdictions for 2009 (Minnesota and Colorado), cost recovery of program costs is accomplished through a combination of base rate revenue and a non-fuel rider revenue mechanism, similar to a fuel cost recovery adjustment mechanism. The revenue billed to customers recovers incurred costs for the conservation programs and an incentive amount that is designed to compensate the operating companies for the achievement of energy conservation goals, including lost sales or margin. In these jurisdictions, the operating company has recorded a regulatory asset (when appropriate) to reflect the amount of costs or earned incentives that have not yet been collected from customers. In some jurisdictions (Texas and Wisconsin), program costs are approved and recovered through base rate revenue, without the use of a non-fuel rider.

DSM/CIP Accounting

Our accounting for DSM/CIP program costs and incentives involve (1) recording a regulatory asset or liability, which is governed by Accounting Standards Codification (“ASC”) 980-340-25-1, Regulated Operations - Effects of Regulation, and (2) ASC 980-605-25, Regulated Operations - Alternative Revenue Programs.

The operating companies defer all or part of an incurred cost that would otherwise be charged to expense if both of the following criteria are met:

a. It is probable that future revenue in an amount at least equal to the deferred cost will result from inclusion of that cost in allowable costs for rate-making purposes.

b. Based on available evidence, the future revenue will be provided to permit recovery of the previously incurred cost rather than to provide for expected levels of similar future costs. If the revenue will be provided through a rate-adjustment clause, this criterion requires that the regulator’s intent clearly be to permit recovery of the previously incurred cost.

A cost that does not meet these asset recognition criteria at the date the cost is incurred shall be recognized as a regulatory asset when it does meet those criteria at a later date.

The operating companies follow ASC 980-605-25 to account for any earned incentives approved under their DSM/CIP programs. Revenue and a regulatory asset are recognized when all of the following conditions are met:

a. The program is established by an order from the operating companies regulatory commission that allows for automatic adjustment of future rates;

b. The amount of additional revenues is objectively determinable and is probable of recovery; and

c. The additional revenues will be collected within 24 months following the end of the annual period in which they are recognized.

As of December 31, 2009, incentive revenue for DSM/CIP programs has only been recognized in Minnesota and Colorado. The earned incentives are reviewed, approved and recovered within 24 months in Minnesota, but the recovery period for a portion of the incentives in Colorado is currently longer than 24 months and, accordingly, revenue has not been recognized for the portion of the earned incentive that we expect to collect beyond the 24 month period requirement. Once the incentive is collectible within a 24 month period, the revenue and regulatory asset are recognized.

Financial Statement Presentation

In 2008, the Companies began separately disclosing DSM/CIP operating expenses in its income statement presented on Form 10-K and subsequent filings. The separate disclosure was the result of the growth of these programs and the impact on other income statement line item classifications. The break out of these expenses provides the reader of our financial statements better insight to the drivers of our operating margin and expenses. The companies disclosed the reclassification of DSM/CIP from other operating and maintenance expenses and depreciation and amortization in their Form 10-Ks and 10-Qs. All conservation program regulatory assets are separately disclosed in the regulatory asset and liabilities footnote along with the remaining amortization period of the deferred costs.

20. Segments and Related Information, pare 147

4. Please expand your disclosure regarding assigned and allocated costs to describe the types of costs that are directly assigned to a segment, allocated based on causation allocators and allocated based on a general allocator.

Response:

The operating companies have established a general ledger system to maintain accounting records that conform with the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

PSCo, NSP-Minnesota and NPS-Wisconsin are regulated utilities providing both electric and gas utility services. Some expenses are identified as “common” and these amounts must be allocated to report income from continuing operations for regulated electric and regulated natural gas utility segments. SPS is a regulated electric utility and all costs are directly assigned.

Consistent with the allocation methodologies approved by state and federal regulators, PSCo, NSP-Minnesota and NPS-Wisconsin allocate common costs using cost causation allocators, where practical and a general allocator where not practical. The primary expenses that are allocated include common depreciation expenses, common operating and maintenance expenses, and interest expense. The allocated amounts are relatively immaterial, compared to the directly assigned amounts.

In Xcel Energy’s segment and related information footnote, approximately 91% of all expenses are directly assigned to regulated electric, regulated natural gas or all other and used for segment reporting. Additionally, the allocation methods have been applied consistently from year to year and do not significantly impact the comparability of the segment results. Accordingly, the Companies plan to modify their future segment disclosures, on a prospective basis beginning with our September 30, 2010 Quarterly Report on Form 10-Q, in substantially the following manner:

To report income from continuing operations for regulated electric and regulated natural gas utility segments the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common operating and maintenance expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

5. Please disclose total assets for each reportable segment and the items required by FASB ASC 280-10-50-25.

Response:

ASC 280-10-50-22 requires disclosure of profit or loss and total assets for each reportable segment, and ASC 280-10-50-25 requires disclosure of the amount of investments in equity method investees and additions to certain long-lived assets, including fixed assets, for each reportable segment. However, ASC 280-10-50-26 states that if no asset information is provided for a reportable segment, that fact and the reason therefore shall be disclosed.

ASC 280 goes on to clarify in paragraph 10-50-27:

The amount of each segment item reported shall be the measure reported to the chief operating decision maker for purposes of making decisions about allocating resources to the segment and assessing its performance. Adjustments and eliminations made in preparing a public entity’s general-purpose financial statements and allocations of revenues, expenses, and gains or losses shall be included in determining reported segment profit or loss only if they are included in the measure of the segment’s profit or loss that is used by the chief operating decision maker. Similarly, only those assets that are included in the measure of the segment’s assets that is used by the chief operating decision maker shall be reported for that segment. If amounts are allocated to reported segment profit or loss or assets, those amounts shall be allocated on a reasonable basis.

We do not allocate total assets by segment for internal reporting used by our chief operating decision maker. Additionally, reflecting the total assets and additions to long lived assets for each reportable segment on a reasonable basis is not practicable for Xcel Energy as there are assets shared between the regulated electric utility reportable segment and the regulated natural gas utility reportable segment, and would be unfairly represented if the assets were displayed in both reportable segments, were allocated to one particular reportable segment, or were allocated arbitrarily between the two reportable segments.

Using the June 30, 2010 as an example, disclosures comparable to the following will be added to future filings of Quarterly and Annual Reports on Form 10-Q and 10-K:

Xcel Energy had equity investments in unconsolidated subsidiaries of $101.6 million and $104.5 million of as of June 30, 2010 and Dec. 31, 2009, respectively included in the regulated natural gas segment.

Total asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary allocations that are not routinely made, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

21. Summarized Quarterly Financial Data (Unaudited), page 149

6. Please present gross profit for each quarterly period presented. Refer to Item 302(a) of Regulation S-K.

Response:

We understand the requirement of Item 302(a) of Regulation S-K requires the disclosure of gross profit in selected quarterly financial data. However, SAB Topic 6: Interpretations of Accounting Series Releases and Financial Reporting Releases, G.1a, Question 2, asks, “If a company is in a specialized industry where “gross profit” generally is not computed (e.g., banks, insurance companies and finance companies), what disclosure should be made to comply with the requirements of Item 302(a)(1)?”

“Interpretive Response: Companies in specialized industries should present summarized quarterly financial data which are most meaningful in their particular circumstances. For example, a bank might present interest income, interest expense, provision for loan losses, security gains or losses and net income. Similarly, an insurance company might present net premiums earned, underwriting costs and expenses, investment income, security gains or losses and net income.”

The regulated public utilities industry is a specialized industry where “gross profit” generally is not considered a key financial metric and, therefore, is not presented in financial reports. A regulated utility’s rates are generally established based on an overall cost of service calculation, which includes all operating expenses. Therefore, we disclose operating income (revenues less operating expenses) in our quarterly financial data since we believe it is more a more meaningful financial metric to investors as well as regulators. Accordingly, we present operating income in lieu of gross profit in our footnote disclosure of Summary Quarterly Financial Data. This presentation is consistent with substantially all of the reporting companies in the regulated public utility industry.

In connection with the above responses to the Staff’s comments, we acknowledge that:

· the company is responsible for the adequacy and accuracy of the disclosure in the filing;

· staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

· the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please direct any further comments or questions to me at (612) 215-4560

Very truly yours,

/s/ TERESA S. MADDEN
Teresa S. Madden
Vice President and Controller