PART 1. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(Thousands of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Operating revenues:
Electric utility	$	577,374		$	505,072		$	1,153,271		$	1,016,381
Natural gas utility	198,864			161,782			651,850			554,312
Steam and other	6,970			6,378			17,364			14,459
Total operating revenues	783,208			673,232			1,822,485			1,585,152

Operating expenses:
Electric fuel and purchased power	327,514			294,453			667,717			577,065
Cost of natural gas sold and transported	136,528			103,621			496,849			405,266
Cost of sales – steam and other	3,795			3,391			10,386			8,519
Other operating and maintenance expenses	138,085			129,563			262,306			258,522
Depreciation and amortization	59,454			54,718			118,919			107,139
Taxes (other than income taxes)	21,901			21,521			44,664			43,672
Total operating expenses	687,277			607,267			1,600,841			1,400,183

Operating income	95,931			65,965			221,644			184,969

Other income (expense):
Nonoperating expenses, net of interest and other income (see Note 7)	(2,392		)	(2,933		)	(5,974		)	(5,770		)
Allowance for funds used during construction – equity	645			2,520			1,230			6,021
Total other income (expense)	(1,747		)	(413		)	(4,744		)	251

Interest charges and financing costs:
Interest charges – including other financing costs of $1,739, $1,932, $3,446 and $4,013, respectively	37,197			37,708			74,689			77,119
Allowance for funds used during construction – debt	(1,029		)	(1,572		)	(2,395		)	(4,268		)
Total interest charges and financing costs	36,168			36,136			72,294			72,851

Income before income taxes	58,016			29,416			144,606			112,369
Income taxes	10,828			1,484			31,811			29,271
Net income	$	47,188		$	27,932		$	112,795		$	83,098

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of dollars)

	Six Months Ended June 30,
	2005			2004
Operating activities:
Net income	$	112,795		$	83,098
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	125,817			107,656
Deferred income taxes	19,814			16,535
Amortization of investment tax credits	(1,986		)	(2,781		)
Allowance for equity funds used during construction	(1,230		)	(6,021		)
Change in accounts receivable	(1,763		)	(6,978		)
Change in accrued unbilled revenue	10,514			(43,247		)
Change in inventories	67,222			45,649
Change in recoverable purchased natural gas and electric energy costs	121,380			97,247
Change in prepayments and other current assets	(6,157		)	10,438
Change in accounts payable	(108,172		)	(7,292		)
Change in other current liabilities	(28,360		)	(34,121		)
Change in other noncurrent assets	2,705			(10,695		)
Change in other noncurrent liabilities	19,385			34,243
Net cash provided by operating activities	331,964			283,731

Investing activities:
Capital/construction expenditures	(179,132		)	(181,489		)
Proceeds from disposition of property, plant and equipment	¾			4,793
Allowance for equity funds used during construction	1,230			6,021
Other investments	1,394			(5,512		)
Net cash used in investing activities	(176,508		)	(176,187		)

Financing activities:
Short-term repayments – net	(187,855		)	(846		)
Proceeds from issuance of long-term debt	6,000			¾
Repayment of long-term debt, including reacquisition premiums	(110,710		)	(146,050		)
Capital contribution from parent	199,880			50,045
Dividends paid to parent	(62,564		)	(121,465		)
Net cash used in financing activities	(155,249		)	(218,316		)

Net increase (decrease) in cash and cash equivalents	207			(110,772		)
Cash and cash equivalents at beginning of period	726			125,101
Cash and cash equivalents at end of period	$	933		$	14,329

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	73,523		$	77,062
Cash paid for income taxes (net of refunds received)	$	30,524		$	15,969

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of dollars)

	June 30, 2005			Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	933		$	726
Accounts receivable — net of allowance for bad debts: $14,096 and $14,734, respectively	330,242			341,946
Accounts receivable from affiliates	33,428			19,961
Accrued unbilled revenues	162,340			172,854
Recoverable purchased natural gas and electric energy costs	50,835			172,215
Materials and supplies inventories — at average cost	43,384			44,897
Fuel inventory — at average cost	23,561			23,533
Natural gas inventory — at average cost	84,248			149,985
Derivative instruments valuation — at market	135,883			54,450
Prepayments and other	73,146			73,896
Total current assets	938,000			1,054,463
Property, plant and equipment, at cost:
Electric utility plant	6,236,054			6,123,791
Natural gas utility plant	1,727,435			1,691,895
Construction work in progress	152,751			200,118
Common utility and other	833,370			786,025
Total property, plant and equipment	8,949,610			8,801,829
Less accumulated depreciation	(2,935,330		)	(2,862,494		)
Net property, plant and equipment	6,014,280			5,939,335
Other assets:
Other investments	34,590			35,985
Regulatory assets	224,513			246,564
Derivative instruments valuation – at market	182,653			137,846
Other	36,881			38,413
Total other assets	478,637			458,808
Total assets	$	7,430,917		$	7,452,606
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	260,812		$	135,854
Short-term debt	—			186,300
Note payable to affiliate	9,100			10,655
Accounts payable	317,532			415,652
Accounts payable to affiliates	25,813			35,865
Taxes accrued	43,812			72,446
Dividends payable to parent	—			62,565
Derivative instruments valuation — at market	19,527			60,586
Accrued interest	37,144			41,104
Other	82,923			87,294
Total current liabilities	796,663			1,108,321
Deferred credits and other liabilities:
Deferred income taxes	779,673			744,326
Deferred investment tax credits	64,970			66,955
Regulatory liabilities	611,787			475,136
Customers advances for construction	284,728			284,534
Minimum pension liability	62,669			62,669
Derivative instruments valuation – at market	163,123			157,130
Benefit obligations and other	117,059			87,022
Total deferred credits and other liabilities	2,084,009			1,877,772
Long-term debt	1,945,766			2,179,961
$500 million, 5-year, unsecured credit facility, weighted average interest rate of 6.25% at June 30, 2005	6,000			—
Common stock – authorized 100 shares of $0.01 par value; outstanding 100 shares	—			—
Premium on common stock	2,181,783			1,981,903
Retained earnings	505,541			392,746
Accumulated other comprehensive loss	(88,845		)	(88,097		)
Total common stockholder’s equity	2,598,479			2,286,552
Commitments and contingencies (see Note 3 and Note 4)
Total liabilities and equity	$	7,430,917		$	7,452,606

See Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of PSCo and its subsidiaries as of June 30, 2005, and Dec. 31, 2004; the results of its operations for the three and six months ended June 30, 2005 and 2004; and its cash flows for the six months ended June 30, 2005 and 2004. Due to the seasonality of electric sales of PSCo, quarterly results are not necessarily an appropriate base from which to project annual results.

The significant accounting policies of PSCo are set forth in Note 1 to its consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2004. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K.

1. Significant Accounting Policies

FASB Interpretation No. 47 (FIN No. 47) – In April 2005, the Financial Accounting Standards Board (FASB) issued FIN No. 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations pursuant to Statement of Financial Accounting Standard (SFAS) No. 143 - “Accounting for Asset Retirement Obligations”. The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the fair value is estimable, even when the obligation is dependent on a future event. FIN No. 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized. Implementation is required to be effective no later than the end of fiscal years ending after Dec. 15, 2005. Additionally, FIN No. 47 will permit but not require restatement of interim financial information during any period of adoption. Both recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis are required for transition purposes. PSCo is evaluating the impact of FIN No. 47, however, it is not expected to have a material impact on results of operations or financial position due to the expected recovery of asset retirement costs in customer rates.

Accounting for Uncertain Tax Positions – On July 14, 2005, the FASB issued an exposure draft on accounting for uncertain tax positions under SFAS No. 109. See Note 3 to the consolidated financial statements for further discussion.

Reclassifications – Certain items in the statement of income for the three and six months ended June 30, 2004 have been reclassified to conform to the 2005 presentation. These reclassifications had no effect on net income.

2. Regulation

Federal Regulation

Market-Based Rate Authority — The Federal Energy Regulatory Commission (FERC) regulates the wholesale sale of electricity. In order to obtain market-based rate authorization from the FERC, utilities such as PSCo have been required to submit analyses demonstrating that they did not have market power in the relevant markets. PSCo was previously granted market-based rate authority by the FERC.

In 2004, the FERC adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) as a revised test to assess market power. Passage of the two screens creates a rebuttable presumption that an applicant does not have market power, while the failure creates a rebuttable presumption that the utility does have market power. An applicant or intervenor can rebut the presumption by performing a more extensive delivered-price test analysis. If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC. The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power.

Xcel Energy filed the required analysis applying the FERC’s two indicative screens on behalf of itself and PSCo with the FERC on Feb. 7, 2005. This analysis demonstrated that PSCo did not pass the pivotal supplier analysis in its own control area and all adjacent markets or the market share analysis in its own control area. Numerous parties filed interventions and requested that FERC set the analysis for hearing. Certain parties asked the FERC to revoke the market-based rate authority of PSCo.

On June 2, 2005, the FERC issued an order initiating a proceeding pursuant to Section 206 of the Federal Power Act to investigate PSCo’s market-based rate authority within its own control area. The refund effective date that has been set as part of that investigation for such sales is Aug. 12, 2005.

By Aug. 1, 2005, PSCo must either submit a delivered price test analysis to support the grant of market-based rate authorization for sales within its control area, make a mitigation proposal to eliminate any ability that it has to exercise market power, or adopt the FERC’s default mitigation proposal, namely to adopt cost-based rates that would apply to sales within its control area.

The FERC also required that Xcel Energy make a compliance filing providing information, including information regarding the FERC’s affiliate abuse component of its market power analysis and the allegations regarding that component made by an intervenor within 30 days of the date of issuance of its order. The latter compliance filing was submitted on July 5, 2005. Xcel Energy plans to withdraw its market-based rate authority on a prospective basis for sales with loads sinking within PSCo’s control area. The cost-based rate that will be proposed for PSCo is not expected to have a significant impact on commodity marketing operations.

FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of PSCo and Southwestern Public Service Company (SPS) an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff (OATT). PSCo and SPS requested an increase in annual transmission service and ancillary services revenues of $6.1 million. As a result of a settlement with certain PSCo wholesale power customers in 2003, their power sales rates would be reduced by $1.4 million. The net increase in annual revenues proposed is $4.7 million, of which $3.0 million is attributable to PSCo. The FERC suspended the filing and delayed the effective date of the proposed increase to June 1, 2005. The rate increase application also includes PSCo and SPS adopting an annual formula rate for transmission service pricing as previously approved by the FERC for other transmission providers, which would provide annual rate changes reflecting changes in cost and usage. The case is currently pending settlement judge procedures and interim rates went into effect on June 1, 2005, subject to refund.

Other Regulatory Matters

Resource Plan — In December 2004, the Colorado Public Utilities Commission (CPUC) approved a settlement agreement between PSCo and many intervening parties concerning its future resource plan. As a part of the settlement the CPUC approved PSCo’s plan to construct a 750-megawatt net output pulverized coal-fired unit at the Comanche Station located near Pueblo, Colo. and transfer up to 250 megawatts of capacity ownership from the 750-megawatt unit to Intermountain Rural Electric Association (IREA) and Holy Cross Energy, if negotiations with those entities are successful.

On July 20, 2005, Holy Cross Energy filed a lawsuit requesting declaratory judgment regarding their rights to participate in the Comanche 3 project. PSCo is in discussions with Holy Cross Energy to resolve the difference between the parties.

On April 12, 2005, PSCo signed agreements with IREA that define the respective rights and obligations of PSCo and IREA in the transfer of 25 percent of the capacity ownership of the new 750-megawatt Comanche unit to IREA. Transfer of ownership to IREA is contingent upon IREA’s successful completion of its financing, among other things, and is expected to occur in late 2005 or early 2006.

On April 8, 2005, the Colorado Department of Public Health and Environment issued draft air quality permits for the new Comanche unit for public comment. On July 5, 2005, final air quality permits were issued for the new coal-fired unit, as well as additional emission controls on Comanche’s two existing units. Construction on the plant is planned to commence in the fall of 2005.

On Feb. 16, 2005, PSCo filed an application with the CPUC for a certificate of public convenience and necessity for construction of the transmission associated with the new Comanche unit. The transmission project consists of:

• Construction of a new double circuit 345-kilovolt transmission facility between Comanche station and Midway substation;

• Installation of autotransformers to allow an existing double circuit transmission facility operating at 230 kilovolts between Midway substation and the Daniels Park substation to operate at 345 kilovolts; and

• Reconstruction of an existing facility to a double circuit 345-kilovolt capable facility, but operated initially at 230 kilovolts.

The CPUC set this matter for hearing before an administrative law judge and hearings were held regarding PSCo’s application in June 2005. A decision is expected later this year.

On June 10, 2005, PSCo filed a petition with the City of Pueblo, Colo. Requesting that the city annex the Comanche power plant. This petition is scheduled for a final determination by the Pueblo City Council on Sept. 12, 2005. Construction cannot begin without the necessary permits. If annexation is denied, PSCo will petition for construction permits through Pueblo County. PSCo cannot predict the outcome of this request.

Effective July 19, 2005, PSCo secured a long-term water supply contract with the Pueblo Board of Water Works for all three

Comanche units. The agreement is predicated on the approval of annexation of the plant site into the City of Pueblo.

In addition to the new Comanche unit and PSCo demand side management (DSM) approved in the settlement agreement, the remainder of PSCo’s resource needs will be met by the least cost combination of purchases of renewable energy, supply side resources, and contracted DSM.

PSCo issued a renewable energy request for proposal (RFP) on August 17, 2004. In November, 2004, PSCo received 33 bids for approximately 4,600 megawatts of wind and other renewable generation. In February and March 2005, PSCo entered into contracts to purchase the energy from two wind generation projects, a 60-megawatt project and 69-megawatt project, each to be constructed in 2005.

On Feb. 24, 2005, PSCo issued an all-source solicitation, comprised of RFPs for dispatchable resources, non-dispatchable resources and DSM resources, seeking approximately 2,500 megawatts of additional electric supply and demand-side resources that are scheduled to begin providing service in 2006 through 2013. On May 17, 2005, PSCo received bids for approximately 17,000 megawatts, including proposals for coal-fired generation, gas-fired generation, wind generation, biomass generation and DSM. PSCo is in the process of evaluating the bids received in response to the RFP and expects to begin negotiations with the winning projects later this year.

Renewable Portfolio Standards - In November 2004, an amendment to the Colorado statutes was passed requiring implementation of a renewable energy portfolio standard for electric service. The new law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources. Generation of electricity from renewable resources, particularly solar energy, may be a higher-cost alternative to traditional fuels, such as coal and natural gas. Such incremental costs are expected to be recovered from customers. On March 29, 2005, the CPUC initiated a proceeding to determine the rules and regulations required to implement the renewable portfolio standard. The CPUC has received two rounds of comments with respect to proposed rules and has scheduled three days of hearings beginning Aug. 30, 2005 regarding the rulemaking. Final rules are expected to become effective later this year.

Natural Gas Rate Case – On May 27, 2005, PSCo filed for an increase of natural gas base rates in Colorado. The proposed increase, factoring in current costs of natural gas, would increase overall customer bills by approximately $34 million, or 3 percent annually. PSCo supplemented its filing with the CPUC on July 8, 2005. The CPUC has scheduled a prehearing conference for Aug. 3, 2005. It is anticipated that the request, if approved by the CPUC, would become effective early in 2006.

3. Tax Matters — Corporate-Owned Life Insurance

Interest Expense Deductibility — P.S.R. Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo, owns and manages permanent life insurance policies, known as corporate-owned life insurance (COLI) policies, on some of PSCo’s current and former employees. At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The Internal Revenue Service (IRS) has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 2001.

After consultation with tax counsel, Xcel Energy contends that the IRS determination is not supported by tax law. Based upon this assessment, management believes that the tax deduction of interest expense on the COLI policy loans is in full compliance with the law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.

In April 2004, Xcel Energy filed a lawsuit in U.S. District Court for the District of Minnesota against the IRS to establish its entitlement to deduct policy loan interest for tax years 1993 and 1994. In December 2004, Xcel Energy filed suit in U.S. Tax Court in Washington D.C. for tax years 1995 through 1997 and again in March 2005 for tax years 1998 and 1999. Xcel Energy requested that the tax court consolidate and stay its petitions pending the decision in the district court litigation. On May 2, 2005, Xcel Energy filed a motion for summary judgment in the district court litigation. On June 22, 2005, the government also filed a summary judgment motion arguing, for the first time, that Xcel Energy lacked an insurable interest in the lives of its employees, and therefore, the policies are allegedly void. Xcel Energy denies that this claim has any merit. A court hearing is scheduled for August 19, 2005 to hear both motions. The litigation could require several years to reach final resolution. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on PSCo’s financial position and results of operations and cash flows. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce earnings by an estimated $350 million. In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2005, is approximately $415 million. PSCo estimates its annual earnings for

2005 would be reduced by $40 million, after tax, if COLI interest expense deductions were no longer available.

Accounting for Uncertain Tax Positions — In July 2004, the FASB discussed potential changes or clarifications in the criteria for recognition of tax benefits, which may result in raising the threshold for recognizing tax benefits, which have some degree of uncertainty. On July 14, 2005, the FASB issued an Exposure Draft on accounting for uncertain tax positions under SFAS No. 109. If adopted as proposed, the interpretation will be effective Dec. 31, 2005 and only tax benefits that meet the probable recognition threshold may be recognized or continue to be recognized on the effective date. Initial derecognition amounts will be reported as a cumulative effect of a change in accounting principle. The exposure draft requires a 60-day comment period, which will be followed by deliberations. Accordingly, if adopted as proposed, PSCo would report as a cumulative effect of a change in accounting principle in its 2005 income statement a charge of approximately $350 million relating to COLI tax benefits and additional interest costs. Under the proposed interpretation penalties are to be accrued when a tax position does not meet the minimum statutory threshold. PSCo believes the COLI position exceeds the minimum statutory threshold and, therefore, does not expect to accrue penalties under the interpretation. However, if penalties were required to be accrued they would be approximately $65 million. PSCo has not yet evaluated the impact the proposed interpretation would have on other existing income tax positions.

4. Commitments and Contingent Liabilities

Environmental Contingencies

PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense for such unrecoverable amounts in its consolidated financial statements.

Federal Clean Water Act - The federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the Environmental Protection Agency (EPA) published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require PSCo to perform additional environmental studies at three power plants in Colorado to determine the impact the facilities may be having on aquatic organisms vulnerable to injury. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these plants. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. Based on the limited information available, total capital costs to PSCo are estimated at approximately $2 million. Actual costs may be significantly higher or lower depending on issues such as the resolution of outstanding third-party legal challenges to the rule.

Fort Collins Manufactured Gas Plant (MGP) Site — Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property. An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the City of Fort Collins and Schrader Oil Co., under which PSCo will perform remediation and monitoring work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring. In May 2005, PSCo filed with the CPUC for recovery of the associated costs through its natural gas rate case.

In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases increased the migration and environmental impact of the MGP byproducts at the site. PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River. On June 27, 2005, Wayne K. Shrader, an owner of Schrader Oil Co., gave notice of his intent to sue PSCo and the City of Fort Collins pursuant to the Resource Conservation and Recovery Act alleging conditions at the Poudre River site “may be causing an imminent and substantial endangerment.” The notice of intent to sue alleges the City’s remedial efforts, as well as the solvents on City property, caused contamination. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself in any suit which may be filed.

Notice of Violation - On Nov. 3, 1999, the U.S. Department of Justice filed suit against a number of electric utilities for alleged violations of the federal Clean Air Act’s New Source Review (NSR) requirements. The suit is related to alleged modifications of electric generating plants located in the South and Midwest. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including PSCo, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, PSCo responded to the EPA’s initial information

requests. On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the NSR requirements of the Clean Air Act at the Comanche and Pawnee plants in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR equipment replacement rulemaking promulgated in October 2003. On Dec. 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed this rule while it considers challenges to it. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the Clean Air Act, the EPA met with Xcel Energy in September 2002 to discuss the NOV.

On March 10, 2005, the Rocky Mountain Environmental Labor Coalition (RMELC) provided notice to PSCo of its intent to sue PSCo for alleged violations of the Clean Air Act at the Comanche plant. The notice of intent to sue alleges PSCo has violated the Clean Air Act’s Prevention of Significant Deterioration regulations based on allegations that maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. The allegations are the same as those presented in the NOV. On June 9, 2005, Citizens for Clean Air and Water in Pueblo/Southern Colorado (CCAP) and Leslie Glustrom provided notice of intent to sue PSCo for alleged violations of the Clean Air Act at the Comanche Plant. The allegations in the notice of intent to sue by CCAP and Ms. Glustrom are substantially identical to those of RMELC. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself in any suit which may be filed.

Legal Contingencies

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on PSCo’s financial position and results of operations.

Hill, et al., vs. PSCo, et al. – As previously reported, in late October 2003, there were two wildfires in Colorado, one in Boulder County and the other in Douglas County. There was no loss of life, but there was property damage associated with these fires. Parties have asserted that trees falling into PSCo distribution lines may have caused one or both fires. On Jan. 14, 2004, an action against PSCo relating to the fire in Boulder County was filed in Boulder County District Court. There are now 46 plaintiffs, including individuals and insurance companies, and three co-defendants, including PSCo. The plaintiffs asserted damages in excess of $35 million. On or about June 23, 2005, PSCo reached a confidential settlement with all parties, as well as the United States Forest Service and the Denver Public Schools, settling claims in connection with the fire in Boulder County. The financial impact of the settlement is not expected to be material to PSCo.

Other Contingencies

The circumstances set forth in Note 12 to the consolidated financial statements in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2004 and Notes 2 and 3 of this Quarterly Report on Form 10-Q, appropriately represent, in all material respects, the current status of respective commitments and contingent liabilities and are incorporated herein by reference. The following are unresolved contingencies that are material to Xcel Energy’s financial position:

• Tax Matters — See Note 3 to the accompanying consolidated financial statements for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest; and

5. Fuel Supply and Costs

PSCo recently notified the United States Department of Energy (DOE) of reduced inventories of coal at its electric generating stations. Delivery of coal from the Powder River Basin region in Wyoming has been disrupted by train derailments and other operational problems purportedly caused by deteriorated rail track beds of approximately 100 miles in length in Wyoming. The BNSF Railway Co. (BNSF) and the Union Pacific Railroad (UPRR) jointly own the rail line. The BNSF operates and maintains the rail line. The Powder River Basin is a primary source of coal used by PSCo in the operation of its two coal-fired electric generating stations. Reduced deliveries of coal have reduced the inventories of coal at PSCo’s electric generating stations.

BNSF and UPRR have indicated that repair and reconstruction of the deteriorated sections of rail track beds may take the balance of the year. While BNSF and UPRR have begun to repair the rail beds, they are working with PSCo to identify options in the

interim to increase the rate of coal deliveries. Additionally, PSCo has been analyzing the potential magnitude, likelihood and effects of reduced coal deliveries to its generating stations and developing an interim plan to conserve coal. The interim plan includes modifying the dispatch of their coal-fired electric generating stations to conserve existing coal supplies until coal deliveries return to normal levels. PSCo has increased power purchases from third parties and, where practicable, has increased the use of natural gas for electric generation to replace the coal-fired electric generation. Also, PSCo has been in contact with its wholesale customers to identify options to reduce sales levels if necessary. PSCo also anticipates utilizing larger capacity rail cars to help mitigate coal supply issues. Based upon these cooperative efforts, including improvements in scheduling and operating practices, PSCO is optimistic it may be able to substantially reduce its use of natural gas later this summer.

The cost of purchased power and natural gas for electric generation is higher than that for coal-fired electric generation, and the use of these sources to replace coal-fired electric generation will increase the price of electricity for retail and wholesale customers.

PSCo has discussed this situation with the staff of the regulatory commission in Colorado.

In Colorado, PSCo is subject to several retail adjustment clauses that recover fuel, purchased energy and resource costs. The Electric Commodity Adjustment (ECA) is an incentive adjustment mechanism that compares actual fuel and purchased energy expenses in a calendar year to a benchmark formula. The ECA provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. Any cost in excess of the $11.25 million cap is completely recovered from customers, while any savings in excess of the $11.25 million cap is completely refunded to customers. Subject to the terms of the ECA, PSCo anticipates it will recover the increased fuel and purchased energy costs greater than the cap from its customers. At June 30, 2005, no accrual either positive or negative had been recorded relative to the ECA incentive mechanism.

While PSCo believes that it should be allowed to recover these higher costs, if all or a significant portion of these higher costs are not recovered or there is a significant lag in recovery, this could have a significant impact on the 2005 financial results of PSCo.

6. Derivative Valuation and Financial Impacts

PSCo records all derivative instruments on the balance sheet at fair value unless exempted as a normal purchase or sale. Changes in non-exempt derivative instrument’s fair value are recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to be reflected in Other Comprehensive Income or to offset related results of the hedged item in the statement of income, to the extent effective. SFAS No. 133 - “Accounting for Derivative Instruments and Hedging Activities,” as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

PSCo records the fair value of its derivative instruments in its Consolidated Balance Sheet as a separate line item identified as Derivative Instruments Valuation for assets and liabilities, as well as current and noncurrent.

Cash Flow Hedges

PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices and interest rates. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income.

At June 30, 2005, PSCo had various commodity-related contracts designated as cash flow hedges extending through 2009. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or natural gas purchased for resale. As of June 30, 2005, PSCo had no amounts accumulated in Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. As of June 30, 2005, PSCo had net gains of $1.5 million accumulated in Other Comprehensive Income related to interest rate cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility, as discussed in Note 10 to the consolidated financial statements reported in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2004. There was no hedge ineffectiveness in the second quarter of 2005.

The impact of the components of hedges on PSCo’s Other Comprehensive Income, included as a component of stockholder’s equity, are detailed in the following table:

	Six Months Ended June 30,
(Millions of Dollars)	2005			2004

Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	15.7		$	17.2
After-tax net unrealized gains related to derivatives accounted for as hedges	3.9			1.7
After-tax net realized gains on derivative transactions reclassified into earnings	(4.6		)	(2.5		)
Accumulated other comprehensive income related to cash flow hedges at June 30	$	15.0		$	16.4

Derivatives Not Qualifying for Hedge Accounting

PSCo has commodity trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statement of Income. The results of these transactions are reported on a net basis within Operating Revenue on the Consolidated Statement of Income.

PSCo also enters into certain commodity-based derivative transactions, not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in accordance with SFAS No. 133.

Normal Purchases or Normal Sales Contracts

PSCo enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from the fair value reporting requirements of SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet these requirements are documented and exempted from the accounting and reporting requirements of SFAS No. 133.

PSCo evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the derivative contracts entered into within the commodity trading operations qualify for a normal designation.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.

7. Detail of Nonoperating Expenses, Net of Interest and Other Income

Interest and other income, net of nonoperating expenses, for the three and six months ended June 30 consists of the following:

	Three months ended June 30,						Six months ended June 30,
(Thousands of dollars)	2005			2004			2005			2004

Interest income	$	800		$	264		$	1,376		$	784
Other nonoperating income	1,652			—			2,244			346
Gain on disposal of assets	—			2,208			—			2,208
Interest expense on corporate-owned life insurance, net of increase in cash surrender value	(4,841		)	(4,617		)	(9,536		)	(8,343		)
Other nonoperating expenses	(3		)	(788		)	(58		)	(765		)
Total nonoperating expenses, net of interest and other income	$	(2,392	)	$	(2,933	)	$	(5,974	)	$	(5,770	)

8. Segment Information

PSCo has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility. Commodity trading operations are not a reportable segment. Commodity trading results are included in the Regulated Electric Utility segment.

(Thousands of dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other		Reconciling Eliminations			Consolidated Total
Three months ended June 30, 2005
Revenues from:
External customers	$	577,374	$	198,864	$	6,970	$	—		$	783,208
Internal customers	56		21		—		(77		)	—
Total revenue	577,430		198,885		6,970		(77		)	783,208
Segment net income	$	38,181	$	4,243	$	4,764	$	—		$	47,188

Three months ended June 30, 2004
Revenues from:
External customers	$	505,072	$	161,782	$	6,378	$	—		$	673,232
Internal customers	52		18		—		(70		)	—
Total revenue	505,124		161,800		6,378		(70		)	673,232
Segment net income	$	18,925	$	3,453	$	5,554	$	—		$	27,932

(Thousands of dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other		Reconciling Eliminations			Consolidated Total
Six months ended June 30, 2005
Revenues from:
External customers	$	1,153,271	$	651,850	$	17,364	$	—		$	1,822,485
Internal customers	114		46		—		(160		)	—
Total revenue	1,153,385		651,896		17,364		(160		)	1,822,485
Segment net income	$	73,807	$	28,321	$	10,667	$	—		$	112,795

Six months ended June 30, 2004
Revenues from:
External customers	$	1,016,381	$	554,312	$	14,459	$	—		$	1,585,152
Internal customers	99		40		—		(139		)	—
Total revenue	1,016,480		554,352		14,459		(139		)	1,585,152
Segment net income	$	48,847	$	27,261	$	6,990	$	—		$	83,098

9. Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended June 30,						Six months ended June 30,
(Millions of dollars)	2005			2004			2005			2004

Net income	$	47.2		$	27.9		$	112.8		$	83.1
Other comprehensive income:
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 6)	1.9			1.7			3.9			1.7
After-tax net realized gains on derivative transactions reclassified into earnings (see Note 6)	(2.3		)	(2.1		)	(4.6		)	(2.5		)
Unrealized gain on marketable securities	—			—			—			0.1
Other comprehensive loss	(0.4		)	(0.4		)	(0.7		)	(0.7		)
Comprehensive income	$	46.8		$	27.5		$	112.1		$	82.4

The accumulated comprehensive income in stockholder’s equity at June 30, 2005 and 2004, relates to valuation adjustments on PSCo’s derivative financial instruments and hedging activities, the mark-to-market component of PSCo’s marketable securities and unrealized losses related to its minimum pension liability.

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three months ended June 30,
	2005			2004			2005			2004
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	12,980		$	13,124		$	1,599		$	1,425
Interest cost	39,496			44,499			13,663			13,402
Expected return on plan assets	(69,484		)	(79,307		)	(6,267		)	(6,351		)
Amortization of transition (asset) obligation	—			(2		)	3,644			3,590
Amortization of prior service cost (credit)	7,496			7,405			(544		)	(540		)
Amortization of net (gain) loss	(39		)	(2,577		)	6,460			5,276
Net periodic benefit cost (credit)	(9,551		)	(16,858		)	18,555			16,802
Settlements and curtailments	—			703			—			—
Credits not recognized due to the effects of regulation	6,500			8,568			—			—
Additional cost recognized due to the effects of regulation	—			—			973			972
Net benefit cost (credit) recognized for financial reporting	$	(3,051	)	$	(7,587	)	$	19,528		$	17,774

PSCo
Net periodic benefit cost	$	2,452		$	1,520		$	10,748		$	11,057
Additional cost recognized due to the effects of regulation	—			—			973			972
Net benefit cost recognized for financial reporting	$	2,452		$	1,520		$	11,721		$	12,029

	Six months ended June 30,
	2005			2004			2005			2004
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	30,230		$	29,474		$	3,342		$	3,050
Interest cost	80,492			82,674			27,530			26,302
Expected return on plan assets	(139,758		)	(151,532		)	(12,850		)	(11,626		)
Amortization of transition (asset) obligation	—			(4		)	7,289			7,290
Amortization of prior service cost (credit)	15,018			15,006			(1,089		)	(1,090		)
Amortization of net (gain) loss	3,410			(7,718		)	13,123			10,826
Net periodic benefit cost (credit)	(10,608		)	(32,100		)	37,345			34,752
Settlements and curtailments	—			703			—			—
Credits not recognized due to the effects of regulation	9,684			18,745			—			—
Additional cost recognized due to the effects of regulation	—			—			1,946			1,945
Net benefit cost (credit) recognized for financial reporting	$	(924	)	$	(12,652	)	$	39,291		$	36,697

PSCo
Net periodic benefit cost	$	7,395		$	3,976		$	21,920		$	20,895
Additional cost recognized due to the effects of regulation	—			—			1,946			1,945
Net benefit cost recognized for financial reporting	$	7,395		$	3,976		$	23,866		$	22,840

Employer Contribution

In July 2005, PSCo contributed $15 million to its bargaining pension plan.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Forward-Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of PSCo during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and notes.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis 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,” “estimate,” “expect,” “objective,” “outlook,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

• Economic conditions, including their impact on capital expenditures and the ability of PSCo to obtain financing on favorable terms, inflation rates and monetary fluctuations;

• Business conditions in the energy business;

• Demand for electricity in the nonregulated marketplace;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where PSCo has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities

and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, PSCo, Xcel Energy or any of its other subsidiaries; or security ratings;

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry;

• State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Social attitudes regarding the utility and power industries;

• Risks associated with the California power market;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Significant slowdown in growth or decline in the U.S. economy, delay in growth or recovery of the U.S. economy or increased cost for insurance premiums, security and other items;

• Risks associated with implementations of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in PSCo’s SEC filings or in other publicly disseminated written documents.

Market Risks

PSCo is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A – Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec. 31, 2004. Commodity price and interest rate risks for PSCo are mitigated due to cost-based rate regulation. At June 30, 2005, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2004.

RESULTS OF OPERATIONS

PSCo’s net income was approximately $112.8 million for the first six months of 2005, compared with approximately $83.1 million for the first six months of 2004.

Electric Utility, Short-term Wholesale and Commodity Trading Margins

Electric fuel and purchased power expense tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers, most fluctuations in fuel and purchased power costs do not significantly affect electric utility margin.

PSCo has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from PSCo’s generation assets and energy and capacity purchased to serve native load. Commodity trading is not associated with PSCo’s generation assets or the energy and capacity purchased to serve native load.

Margins from commodity trading activity conducted at PSCo are partially redistributed to Northern States Power Company, a Minnesota corporation, and Southwestern Public Service Company, both wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenue. Trading revenues are reported net of trading costs in the Consolidated Statements of Income. Commodity trading costs include fuel, purchased power, transmission and other related costs.

The following table details base electric utility, short-term wholesale and commodity trading revenue and margin:

(Millions of dollars)	Base Electric Utility			Short-term Wholesale			Commodity Trading			Consolidated Total

Six months ended June 30, 2005
Electric utility revenue (excluding commodity trading)	$	1,147		$	4		$	—		$	1,151
Electric fuel and purchased power	(664		)	(4		)	¾			(668		)
Commodity trading revenue	¾			¾			154			154
Commodity trading costs	¾			¾			(151		)	(151		)
Gross margin before operating expenses	$	483		$	—		$	3		$	486
Margin as a percentage of revenue	42.1		%	—		%	1.9		%	37.2		%

Six months ended June 30, 2004
Electric utility revenue (excluding commodity trading)	$	992		$	25		$	—		$	1,017
Electric fuel and purchased power	(555		)	(22		)	¾			(577		)
Commodity trading revenue	¾			¾			161			161
Commodity trading costs	¾			¾			(162		)	(162		)
Gross margin before operating expenses	$	437		$	3		$	(1	)	$	439
Margin as a percentage of revenue	44.1		%	12.0		%	(0.6%		)	37.3		%

The following summarizes the components of the changes in base electric revenue and base electric margin for the six months ended June 30:

Base Electric Revenue

(Millions of dollars)	2005 vs. 2004

Sales growth (excluding weather impact)	$	9
Estimated impact of weather	10
Fuel cost recovery	62
Purchased capacity cost adjustment	14
Firm wholesale and capacity revenues	50
Quality of service obligations	7
Transmission and other	3
Total base electric revenue increase	$	155

Base Electric Margin

(Millions of dollars)	2005 vs. 2004

Sales growth (excluding weather impact)	$	8
Estimated impact of weather	8
Purchased capacity costs	(10		)
Financial hedging costs	4
Quality of service obligations	7
ECA incentive accruals	(4		)
2003 retail jurisdictional allocation adjustment	4
Capacity margins	13
Firm wholesale margins	14
Transmission and other	2
Total base electric revenue increase	$	46

Natural Gas Utility Margins

The following table details the change in natural gas revenue and margin. The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. PSCo has a Gas Cost Adjustment mechanism for natural gas sales, which recognizes the majority of the effects of changes in the cost of natural gas purchased for resale and adjusts revenues to reflect such changes in costs upon request by PSCo. Therefore, fluctuations in the cost of natural gas have little effect on natural gas margin.

	Six Months ended June 30,
(Millions of dollars)	2005			2004

Natural gas utility revenue	$	652		$	554
Cost of natural gas sold and transported	(497		)	(405		)
Natural gas utility margin	$	155		$	149

The following summarizes the components of the changes in natural gas revenue and margin for the six months ended June 30:

Natural Gas Revenue

(Millions of dollars)	2005 vs. 2004

Estimated impact of weather on firm sales volume	$	3
Purchased gas adjustment clause recovery	90
Transport and other	5
Total natural gas revenue increase	$	98

Natural Gas Margin

(Millions of dollars)	2005 vs. 2004

Estimated impact of weather on firm sales volume	$	3
Transport and other	3
Total natural gas margin increase	$	6

Non-Fuel Operating Expense and Other Items

The following summarizes the components of the changes in other utility operating and maintenance expense for the six months ended June 30:

(Millions of dollars)	2005 vs. 2004

Lower restricted stock unit accruals	$	(1	)
Higher plant outage related costs	2
Lower litigation costs	(1		)
Higher pension and medical costs	4
Lower 401(k) plan costs	(2		)
Other	1
Total	$	3

Depreciation and amortization expense increased by approximately $11.8 million, or 10.9 percent, for the first six months of 2005 compared with the same period in 2004, primarily due to plant additions and higher software amortization.

Income tax expense increased by approximately $2.5 million for the first six months of 2005, compared with the same period of 2004. The increase was primarily due to an increase in pretax income levels for 2005 as compared to 2004. The effective tax rate was 22.0 percent for the first six months of 2005, compared with 26.0 percent for the same period in 2004. The decrease was primarily due to a lower forecasted annual effective tax rate for 2005 as compared to 2004.

ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2005

		or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Colorado		84-0296600
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1225 17^th Street, Denver Colorado		80202
(Address of principal executive offices)		(Zip Code)

Class		Outstanding at August 1, 2005
Common Stock, $0.01 par value		100 shares

		PART I - FINANCIAL INFORMATION
Item l.		Financial Statements
Item 2.		Management’s Discussion and Analysis
Item 4.		Controls and Procedures
		PART II - OTHER INFORMATION
Item 1.		Legal Proceedings
Item 5.		Other Information
Item 6.		Exhibits

*		Incorporated by reference
10.01*		Xcel Energy Inc. 2005 Omnibus Incentive Plan (Appendix B to Schedule 14A, Definitive Proxy Statement filed April 11, 2005, file no. 001-03034)
10.02*		Xcel Energy Inc. Executive Annual Incentive Award Plan (effective May 25, 2005) (Appendix C to Schedule 14A, Definitive Proxy Statement filed April 11, 2005, file no. 001-03034)
10.03*		Amended Employment Agreement, dated as of June 29, 2005, by and between Xcel Energy Inc., a Minnesota corporation, and Wayne H. Brunetti. (Exhibit 10.01 to Xcel Energy Current Report on Form 8-K, dated June 29, 2005)
31.01		Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

Commission File Number: 001-3280

Employer Contribution

Base Electric Revenue

Part II. OTHER INFORMATION

Public Service Co. of Colorado
(Registrant)


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

/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer