PART I. 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 Sept. 30,						Nine Months Ended Sept. 30,
	2006			2005			2006			2005
Operating revenues
Electric utility	$	644,445		$	654,199		$	1,916,376		$	1,807,470
Natural gas utility	142,422			122,427			885,340			774,277
Steam and other	6,857			6,097			26,264			23,461
Total operating revenues	793,724			782,723			2,827,980			2,605,208

Operating expenses
Electric fuel and purchased power	391,011			394,583			1,157,636			1,062,300
Cost of natural gas sold and transported	78,062			70,032			654,607			566,881
Cost of sales — steam and other	3,203			2,889			14,405			13,275
Other operating and maintenance expenses	140,486			133,189			418,791			395,495
Depreciation and amortization	61,375			60,195			179,895			179,114
Taxes (other than income taxes)	20,083			22,562			64,707			67,226
Total operating expenses	694,220			683,450			2,490,041			2,284,291

Operating income	99,504			99,273			337,939			320,917

Interest and other income (expense) - net (see Note 7)	(4,043		)	(2,207		)	(10,513		)	(8,181		)
Allowance for funds used during construction - equity	1,052			13			1,315			1,243

Interest charges and financing costs
Interest charges — includes other financing costs of $1,509, $1,663, $4,547 and $5,109, respectively	32,951			34,691			101,993			109,380
Allowance for funds used during construction — debt	(3,840		)	(993		)	(9,305		)	(3,388		)
Total interest charges and financing costs	29,111			33,698			92,688			105,992

Income before income taxes	67,402			63,381			236,053			207,987
Income taxes	20,044			17,703			59,656			49,514
Net income	$	47,358		$	45,678		$	176,397		$	158,473

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of dollars)

	Nine Months Ended Sept. 30,
	2006			2005
Operating activities
Net income	$	176,397		$	158,473
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	190,859			189,512
Deferred income taxes	70,736			83,321
Amortization of investment tax credits	(2,962		)	(2,978		)
Allowance for equity funds used during construction	(1,315		)	(1,243		)
Unrealized (gain) loss on derivative instruments	(2,566		)	3,200
Change in accounts receivable	144,710			(2,990		)
Change in accrued unbilled revenue	65,883			(61,041		)
Change in inventories	19,685			(30,796		)
Change in recoverable purchased natural gas and electric energy costs	212,713			76,809
Change in prepayments and other current assets	(50,527		)	80,648
Change in accounts payable	(261,725		)	51,325
Change in other current liabilities	10,991			(16,811		)
Change in other noncurrent assets	(39,767		)	6,805
Change in other noncurrent liabilities	(6,668		)	3,287
Net cash provided by operating activities	526,444			537,521

Investing activities
Capital/construction expenditures	(399,924		)	(283,052		)
Allowance for equity funds used during construction	1,315			1,243
Other investments	(1,472		)	(2,864		)
Net cash used in investing activities	(400,081		)	(284,673		)

Financing activities
Short-term borrowings — net	(98,604		)	(196,889		)
Borrowings under utility money pool arrangement	934,800			¾
Repayments under utility money pool arrangement	(902,400		)	¾
Proceeds from issuance of long-term debt	¾			129,500
Repayment of long-term debt, including reacquisition premiums	(125,997		)	(240,528		)
Capital contribution from parent	193,185			199,880
Dividends paid to parent	(129,655		)	(62,564		)
Net cash used in financing activities	(128,671		)	(170,601		)

Net increase (decrease) in cash and cash equivalents	(2,308		)	82,247
Cash and cash equivalents at beginning of year	3,662			726
Cash and cash equivalents at end of quarter	$	1,354		$	82,973

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	86,441		$	92,296
Cash paid for income taxes (net of refunds received)	$	30,395		$	38,587

Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	7,774		$	22,685

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of dollars)

	Sept. 30, 2006			Dec. 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	1,354		$	3,662
Accounts receivable — net of allowance for bad debts: $13,205 and $19,381, respectively	346,452			451,944
Accounts receivable from affiliates	8,528			47,746
Accrued unbilled revenues	168,731			234,614
Recoverable purchased natural gas and electric energy costs	17,681			230,393
Materials and supplies inventories — at average cost	44,222			42,602
Fuel inventory — at average cost	32,712			19,582
Natural gas inventory — at average cost	177,838			212,274
Derivative instruments valuation	97,559			78,064
Prepayments and other	79,776			35,218
Total current assets	974,853			1,356,099
Property, plant and equipment, at cost:
Electric utility plant	6,401,297			6,275,046
Natural gas utility plant	1,816,572			1,793,240
Construction work in progress	382,917			209,721
Other	720,127			745,894
Total property, plant and equipment	9,320,913			9,023,901
Less accumulated depreciation	(2,907,608		)	(2,854,757		)
Net property, plant and equipment	6,413,305			6,169,144
Other assets:
Other investments	29,764			29,465
Regulatory assets	242,588			231,801
Derivative instruments valuation	166,115			164,251
Other	28,556			35,191
Total other assets	467,023			460,708
Total assets	$	7,855,181		$	7,985,951
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	101,368		$	126,334
Short-term debt	237,000			335,604
Borrowings on utility money pool, weighted average yield of 5.38% at Sept. 30, 2006	32,400			—
Accounts payable	320,654			578,722
Accounts payable to affiliates	25,233			26,388
Taxes accrued	64,205			81,638
Dividends payable to parent	65,970			—
Derivative instruments valuation	86,626			66,463
Accrued interest	44,139			36,498
Other	76,877			71,206
Total current liabilities	1,054,472			1,322,853
Deferred credits and other liabilities:
Deferred income taxes	932,708			811,961
Deferred investment tax credits	60,022			62,984
Regulatory liabilities	456,197			492,335
Customer advances for construction	276,956			288,397
Derivative instruments valuation	164,053			170,849
Minimum pension liability	86,099			86,099
Benefit obligations and other	124,393			122,511
Total deferred credits and other liabilities	2,100,428			2,035,136
Commitments and contingencies (see Note 4)
Capitalization:
Long-term debt	1,845,463			1,945,973
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares	—			—
Additional paid in capital	2,377,116			2,183,932
Retained earnings	584,936			604,163
Accumulated other comprehensive loss	(107,234		)	(106,106		)
Total common stockholder’s equity	2,854,818			2,681,989
Total liabilities and equity	$	7,855,181		$	7,985,951

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 Sept. 30, 2006, and Dec. 31, 2005; the results of its operations for the three and nine months ended Sept. 30, 2006 and 2005; and its cash flows for the nine months ended Sept. 30, 2006 and 2005. Due to the seasonality of electric and natural gas sales of PSCo, quarterly results are not necessarily an appropriate base from which to project annual results.

Except to the extent updated or described below, the footnotes set forth in the consolidated financial statements in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 appropriately represent, in all material respects, the current status of the footnotes and are incorporated herein by reference.

1. Significant Accounting Policies

FASB Interpretation No. 48 (FIN 48) — In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes —an interpretation of FASB Statement No. 109.” FIN 48 prescribes a comprehensive financial statement model of how a company should recognize, measure, present and disclose uncertain tax positions that the company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. Initial derecognition amounts would be reported as a cumulative effect of a change in accounting principle.

FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. PSCo is assessing the impact of the new guidance on all of its open tax positions.

Statement of Financial Accounting Standards No. 157 — “Fair Value Measurements” (SFAS No. 157) — In September 2006, the FASB issued SFAS No. 157, which enhances existing guidance for measuring assets and liabilities using fair value. SFAS No. 157 provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS No. 157, fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007. PSCo is evaluating the impact of SFAS No. 157 on its financial condition and results of operations.

Statement of Financial Accounting Standards No. 158 — “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income. Although PSCo continues to evaluate the impact of the new pronouncement, preliminary estimates indicate that assets could be increased by approximately $393 million, the loss in other comprehensive income could be decreased by approximately $120 million and liabilities could be increased by approximately $273 million. PSCo is evaluating regulatory accounting treatment, which would allow recognition of this item as a regulatory asset rather than as a charge to other comprehensive income. These estimates reflect the expected deferral of these amounts as regulatory assets or liabilities. The actual impact of the adoption of SFAS No. 158 could differ significantly from this estimate due to plan asset performance for the year and the discount rate in effect at the end of the year when the plans’ liabilities are measured. The implementation of SFAS No.158 will have no impact on net income. SFAS No. 158 is effective as of the end of the fiscal year ending after Dec. 15, 2006.

2. Regulation

FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of PSCo and Southwestern Public Service Company (SPS), an affiliate of PSCo, an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff. PSCo and SPS requested an increase in annual transmission service and ancillary services revenues of $6.1 million. On Feb. 6, 2006, the parties in the proceeding submitted an uncontested offer of settlement that contains a $1.6 million rate increase, a formula transmission service rate, a 10.5 percent rate of return on common equity, and the phased inclusion of PSCo’s 345 kilovolt tie line costs in wholesale transmission service rates. On April 5, 2006, the Federal Energy Regulatory Commission (FERC) issued an order approving the uncontested settlement. PSCo placed the final rates in effect on June 1, 2005 and issued refunds of approximately $3.7 million.

Electric Commodity Adjustment (ECA) — The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA also provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. The formula rate is revised annually and collected or refunded in the following year, if necessary. The current ECA mechanism will expire Jan. 1, 2007. Based on PSCo's analysis of the most recent forecast, a $10.3 million accrual was recorded in the third quarter of 2006.

Electric Rate Case — In April 2006, PSCo filed with the Colorado Public Utilities Commission (CPUC) to increase electricity rates by $208 million annually, beginning Jan. 1, 2007. The request was based on two components, including an increase in base rate revenues of $178 million and an estimated $30 million increase in purchased capacity cost adjustment (PCCA) revenue. The base rate request was based on a return on equity of 11 percent, an equity ratio of 59.9 percent and an electric rate base of $3.4 billion. No interim rate increase was implemented. The PCCA request was based on 2007 projected costs and a revenue credit to customers for one wholesale contract.

On Aug. 18, 2006, PSCo received testimony from 10 intervenor groups, including the staff of the CPUC and the Office of Consumer Counsel (OCC). The intervenor testimony addressed a multitude of cost-of-service issues and recommended various reductions to PSCo’s requested increase. The intervenors’ recommended increases, as subsequently corrected, ranged from $35 million to $91.4 million, exclusive of PCCA revenue. The CPUC staff recommended an overall base rate increase of $83 million. In addition, the staff generally agreed with PSCo’s proposal for a PCCA mechanism through Dec. 31, 2009. The staff’s filed case incorporated a 9.5 percent return on equity, adopted PSCo’s recommended capital structure and reduced depreciation expense by $19.6 million annually.

The OCC recommended, as subsequently corrected, an overall base rate increase of $35 million, which incorporated an 8.5 percent return on equity, adopted PSCo’s capital structure and reduced depreciation expense by $40.5 million annually.

On Sept. 29, 2006, PSCo filed answer testimony in which it advocated for a $206.6 million increase, composed of an approximate $172 million increase in base rate revenues, an estimated $30 million in PCCA revenue and an estimated $4.6 million in ECA revenue to recover certain WindSource program costs. PSCo continued to support an 11.0 percent return on equity, a 60 percent equity ratio and year-end rate base treatment of Comanche construction work in progress costs. The primary changes from the original filing were to propose the recovery of certain WindSource program revenues through the ECA mechanism rather than through base rates, and an update of pension and other benefits expense.

On Oct. 20, 2006, PSCo entered into a comprehensive settlement agreement with several of the parties to the case, including the CPUC staff, the OCC, the Colorado Energy Consumers, The Kroger Co., Climax Molybdenum Company, CF&I Steel, L.P., and the Commercial Group. If approved by the CPUC, the settlement would authorize an overall rate increase, effective Jan. 1, 2007. The settlement provides for an increase in base rates of $107 million, including an increase to depreciation expense of approximately $13.8 million and use of year-end 2006 rate base treatment for Comanche construction work in progress costs; an estimated $39.4 million in PCCA revenue and an estimated $4.6 million in ECA revenue to recover certain WindSource program costs. As a part of the total revenue increase of $151 million, the settlement also included the following terms:

• A 10.50 percent return on equity and a 60 percent equity ratio;

• A PCCA rider for all purchased capacity costs, with no revenue credit;

• Recovery of certain WindSource-related costs through the ECA and the remainder through WindSource rates; and

• Implementation of a residential late payment fee of 1.00 percent.

The settlement also provides for recovery of fuel and purchased energy costs through the ECA. The ECA mechanism would:

• Change quarterly;

• Allow for interest on any deferred balance;

• As noted above, provide for recovery of WindSource-related costs from non-participating customers updated annually to reflect the system costs absent WindSource resources;

• Provide for an incentive if targets for baseload energy production, or purchased energy benefits exceed certain thresholds. If the thresholds are exceeded, sharing under the ECA incentive would be 80 percent to customers and 20 percent to PSCo and

• Sharing with customers of trading margins from system resources (generation-based trading) and non-system resources (proprietary trading) that are over and above the first approximately $1 million in margins achieved for each type of trading. The sharing percentage for generation-based trading is 80 percent to customers and 20 percent to PSCo; the sharing percentage for the proprietary trading is 20 percent to customers and 80 percent to PSCo.

In a filing made with the CPUC on Oct. 20, 2006, the parties requested that the CPUC delay hearings currently scheduled to begin on Oct. 23, 2006 and hold hearings on the settlement beginning on Nov. 2, 2006.

2003 Resource Plan — On June 2, 2006, PSCo filed a motion with the CPUC requesting permission to withdraw an earlier application it made, which requested CPUC approval to shorten the ten-year resource acquisition period of its 2003 resource plan by one year resulting in a nine year acquisition period (2004-2012). PSCo’s original application also sought to reject all bids offering power supplies starting in 2013 that it received in response to its Feb. 24, 2005 all-source solicitation. On June 7, 2006, the CPUC approved PSCo’s motion and directed PSCo to complete the evaluation of bids and negotiation of contracts offering new power supplies starting in year 2013 by Dec. 15, 2006. It also directed PSCo management to approve the selected contracts by Jan. 15, 2007.

Renewable Portfolio Standards — In November 2004, an amendment to the Colorado statutes was passed by referendum requiring implementation of a renewable energy portfolio standard (RES) for electric service. The law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources. During 2006, the CPUC determined that compliance with the RES should be measured through the acquisition of renewable energy credits either with or without the accompanying renewable energy; that the utility purchaser owns the renewable energy credits associated with existing contracts where the power purchase agreement is silent on the issue; that Colorado utilities should be required to file implementation plans and the methods utilities should use for determining the budget available for renewable resources. In April 2006, the CPUC issued rules that establish the process utilities are to follow in implementing the RES. PSCo filed its first annual compliance plan under these rules on Aug. 31, 2006. The plan demonstrates that PSCo will meet the RES beginning in 2007 as required.

On Dec. 1, 2005, PSCo filed with the CPUC to implement a new rate rider that would apply to each customer’s total electric bill, providing approximately $22 million in annual revenue (1.0 percent of total retail revenue). The revenues collected under the rider will be used to acquire sufficient solar generation resources to meet the requirements of the Colorado renewable energy portfolio standard. On Feb. 14, 2006, PSCo and the other parties to the case filed a stipulation agreeing to reduce the rider to 0.60 percent. The CPUC approved the stipulation on February 22, 2006. The rider became effective March 1, 2006. PSCo’s compliance plan will address whether modification to the level of this rider is necessary to meet the requirements of the renewable energy portfolio standard.

On Aug. 31, 2006, PSCo filed with the CPUC an application for approval of its 2007 plan for compliance with the CPUC’s RES rules. As a part of its plan, PSCo requested approval to continue its existing 0.60 percent RES adjustment rider. Through its existing resources and contracts entered into in 2006, PSCo anticipates having sufficient non-solar renewable energy resources to meet the standard through at least 2016. In June 2006, PSCo issued a request for proposal to provide solar renewable energy credits and expects to enter into contracts to meet its obligation for on-site solar resources. On Sept. 1, 2006, PSCo executed a twenty-year solar power purchase agreement, which will provide about 16,000 megawatt hours per year and accompanying solar renewable energy credits beginning in 2008.

PSCo Quality of Service Plan — PSCo was required to make a filing regarding the future of its quality of service plan (QSP), which expires at the end of 2006. In the initial filing, PSCo proposed a service quality monitoring and reporting plan. After reviewing the responses of the CPUC staff and other intervenors, PSCo negotiated a new QSP that will extend through calendar year 2010. The plan establishes performance measures and provides for associated bill credits for failure to achieve regional electric distribution system reliability, electric service continuity and restoration thresholds, customer complaints and telephone response times. If the performance thresholds are not met, the annual bill credit exposures are approximately $7 million for regional reliability and $1 million each for the continuity, reliability, customer complaints and telephone response time thresholds. Each of PSCo’s nine operating regions has its own calculated reliability metric and the bill credits would be apportioned among the regions. PSCo would have to fail the operating threshold two years in a row before paying reliability bill credits. The bill credit levels would not escalate. If the credits are required to be paid, the stated amounts would be grossed up for taxes. The proposed plan is pending CPUC approval.

PSCo entered into a separate stipulation with the local government intervenors and the City of Boulder regarding certain issues they raised in the QSP proceeding. PSCo agreed to incorporate provisions in its electric tariff regarding conducting regular street light outage surveys and establishing benchmarks for standard outage rates and streetlight and traffic signal restoration. The electric tariff will provide for a charge to conduct the street light surveys. The tariff also will provide for payment of credits if PSCo does not restore street lights within a defined period. The CPUC conducted hearings regarding the QSP settlements and deliberated on the new QSP on Sept. 27, 2006. In deliberations, the CPUC approved the as-settled QSP with some modifications. The CPUC requires PSCo to file a replacement QSP by 2010 and to modify some reporting requirements. The CPUC has not issued a final order.

Controlled Outage Investigation — On July 7, 2006, the CPUC discussed a CPUC staff report regarding its investigation of the controlled outages of Feb. 18, 2006, which affected an estimated 323,000 customers in Colorado for approximately 30 minutes. The investigation reviewed natural gas supply issues, the causes of unplanned outages on several PSCo-owned and independent power generation facilities, transmission availability, customer interruption procedures, emergency preparedness and internal and external communications. The CPUC report made over 90 recommendations and directed PSCo to respond within two weeks with its plans to implement certain procedures to address curtailment situations if they arise this summer. The CPUC’s recommendations are directed at ensuring that there is an appropriate level of situational awareness between the operational status of the interdependent gas and electric supply systems so that adequate pipeline delivery pressures are available during critical peak periods. PSCo responded to the report of the CPUC and is in the process of implementing the recommendations. The final order has not been issued by the CPUC.

3. Tax Matters — Corporate-Owned Life Insurance

Interest Expense Deductibility — As previously disclosed, in April 2004, Xcel Energy filed a lawsuit against the U.S. government in the U.S. District Court for the District of Minnesota to establish its right to deduct the policy loan interest expense that had accrued during tax years 1993 and 1994 on policy loans related to its corporate-owned life insurance (COLI) policies that insured certain lives of employees of PSCo. These policies are owned and managed by PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo.

After Xcel Energy filed this suit, the Internal Revenue Service (IRS) sent its two statutory notices of deficiency of tax, penalty and interest for taxable years 1995 through 1999. Xcel Energy has filed U.S. Tax Court petitions challenging those notices. Xcel Energy anticipates the dispute relating to its claimed interest expense deductions for tax years 1993 and later will be resolved in the refund suit that is pending in the Minnesota federal district court and the Tax Court petitions will be held in abeyance pending the outcome of the refund litigation. In the third quarter of 2006, Xcel Energy also received a statutory notice of deficiency from the IRS for tax years 2000 through 2002 and timely filed a Tax Court petition challenging the denial of the COLI interest expense deductions for those years.

On Oct. 12, 2005, the district court denied Xcel Energy’s motion for summary judgment on the grounds that there were disputed issues of material fact that required a trial for resolution. At the same time, the district court denied the government’s motion for summary judgment that was based on its contention that PSCo had lacked an insurable interest in the lives of the employees insured under the COLI policies. However, the district court granted Xcel Energy’s motion for partial summary judgment on the grounds that PSCo did have the requisite insurable interest.

On May 5, 2006, Xcel Energy filed a second motion for summary judgment. Oral arguments were presented on Aug. 8, 2006. A decision on this motion is pending. On Aug. 18, 2006, the U.S. government filed a second motion for summary judgment. Oral arguments were presented on Oct. 12, 2006, with the Court taking the matter under advisement. The district court has ordered the parties to be ready for trial by Jan. 2, 2007 in the event the motions are denied.

Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax 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. As discussed above, the litigation could require several years to reach final resolution. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position, results of operations and cash flows.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2006, would reduce earnings by an estimated $419 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, 2006, is approximately $497 million. PSCo annual earnings for 2006 would be reduced by approximately $44 million, after tax, if COLI interest expense deductions were no longer available.

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. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered 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.

Regional Haze Rules — The U.S. Environmental Protection Agency (EPA) requires states to develop implementation plans to comply with regional haze rules that require emission controls, known as best available retrofit technology (BART), by December 2007. States are required to identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities. Colorado is the first state in Xcel Energy’s region to earnestly begin its BART rule development as the first step toward the December 2007 deadline. PSCo is actively involved in the stakeholder process in Colorado. On May 30, 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART technology or an approved BART alternative to make reasonable progress toward meeting the national visibility goal. On Aug. 1, 2006, PSCo submitted its BART alternatives analysis to the Colorado Air Pollution Control Division. As set forth in its analysis, PSCo estimates that implementation of the BART alternatives will cost approximately $165 million in capital costs, which includes approximately $62 million in environmental upgrades for the existing Comanche Station project. PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2010 and 2012 and must be operational by 2013.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time. PSCo continues to evaluate the strategy for complying with CAMR. Compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both. On June 6, 2006, the Colorado Department of Public Health and Environment issued a draft rule for implementing CAMR in Colorado. The proposed rule provides for fewer mercury allowances than the federal program, which may result in additional implementation costs. The state of Colorado is required to submit a plan to the EPA by Oct. 31, 2006 to limit mercury emissions from coal-fired electric utility steam generating units consistent with federal standards of performance. A stakeholder process is ongoing, with a hearing before the Colorado Air Quality Control Commission currently scheduled for Nov. 16-17, 2006. The capital cost is estimated to be $4.9 million for the mercury control equipment.

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.

Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court for the Southern District of Mississippi. Although PSCo is not named as a party to this litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse effect on PSCo. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ carbon dioxide emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence, and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety.

Comanche 3 Permit Litigation - On Aug. 4, 2005, Citizens for Clean Air and Water in Pueblo and Southern Colorado and Clean Energy Action filed a complaint against the Colorado Air Pollution Control Division alleging that the Division improperly granted permits to PSCo under Colorado’s Prevention of Significant Deterioration program for the construction and operation of Comanche 3. PSCo intervened in the case. On June 20, 2006, the court ruled in PSCo’s favor and held that the Comanche 3 permits had been properly granted and plaintiffs’ claims to the contrary were without merit. Plaintiffs have appealed this decision.

Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO₂) emissions. Although PSCo is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO₂ emissions could have a material adverse effect on PSCo. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO₂ is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO₂ emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO₂ emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals. Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.

Other Contingencies

The circumstances in Notes 11 and 12 to the consolidated financial statements in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Notes 3 and 4 to the consolidated financial statemtents in 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 PSCo’s financial position:

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

5. Short-Term Borrowings and Financing Activities

At Sept. 30, 2006, PSCo had $237.0 million in short-term debt outstanding at a weighted average yield of 5.42 percent.

6. Derivative Valuation and Financial Impacts

PSCo uses a number of different derivative instruments in connection with its utility operations, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. These derivatives instruments are utilized in connection with various commodity prices, certain energy related products, including emission allowances and renewable energy credits, and interest rates. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133— “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133), are recorded at fair value. The presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship. The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory balance. This classification is dependent on the applicability of specific regulation. This includes certain instruments used to mitigate market risk for PSCo and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income.

PSCo records the fair value of its derivative instruments in its Consolidated Balance Sheets as separate line items identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities.

The fair value of all interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions in which PSCo is currently engaged in are discussed below.

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 or deferred as a regulatory asset or liability.

At Sept. 30, 2006, PSCo had various commodity-related contracts designated as cash flow hedges extending through December 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 gas purchased for resale. As of Sept. 30, 2006, PSCo had no amounts in Accumulated Other Comprehensive Loss 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.

PSCo enters into various instruments that effectively fix 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 fair value of these instruments is recorded as a component of Other Comprehensive Income. As of Sept. 30, 2006, PSCo had net gains of $1.5 million in Accumulated 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 gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. There was an immaterial amount of ineffectiveness in the third quarter of 2006.

The impact of qualifying cash flow hedges on PSCo’s Accumulated Other Comprehensive Income, included as a component of stockholder’s equity, is detailed in the following table:

	Nine Months Ended
(Millions of Dollars)	Sept. 30, 2006			Sept. 30, 2005
Accumulated other comprehensive income related to cash flow hedges at Dec. 31	$	14.2		$	15.7
After-tax net unrealized gains related to derivatives accounted for as hedges	—			8.4
After-tax net realized gains on derivative transactions reclassified into earnings	(1.1		)	(9.5		)
Accumulated other comprehensive income related to cash flow hedges at Sept. 30	$	13.1		$	14.6

Fair Value Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item.

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 Statements of Income. The results of these transactions are recorded on a net basis within Operating Revenue on the Consolidated Statements 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 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 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. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.

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

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, PSCo began recording several long-term power purchase agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During the first quarter of 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts will no longer be adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory balances.

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

7. Detail of Interest and Other Income (Expense) — Net

Interest and other income, net of nonoperating expenses, for the three and nine months ended Sept. 30 consisted of the following:

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(Thousands of dollars)	2006			2005			2006			2005

Interest income	$	391		$	1,007		$	2,518		$	2,384
Other nonoperating income	594			628			3,075			2,872
Interest expense on corporate-owned life insurance and other employee-related insurance policies	(3,605		)	(3,540		)	(13,902		)	(13,076		)
Other nonoperating expenses	(1,423		)	(302		)	(2,204		)	(361		)
Total interest and other income (expense) – net	$	(4,043	)	$	(2,207	)	$	(10,513	)	$	(8,181	)

8. Segment Information

PSCo has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility. Commodity trading operations are not a reportable segment and 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 Sept. 30, 2006
Revenues from:
External customers	$	644,445	$	142,422		$	6,857	$	—		$	793,724
Internal customers	35		5			—		(40		)	—
Total revenue	$	644,480	$	142,427		$	6,857	$	(40	)	$	793,724
Segment net income (loss)	$	39,622	$	5,653		$	2,083	$	—		$	47,358

Three months ended Sept. 30, 2005
Revenues from:
External customers	$	654,199	$	122,427		$	6,097	$	—		$	782,723
Internal customers	65		170			—		(235		)	—
Total revenue	$	654,264	$	122,597		$	6,097	$	(235	)	$	782,723
Segment net income (loss)	$	42,337	$	(1,295	)	$	4,636	$	—		$	45,678

(Thousands of dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other		Reconciling Eliminations			Consolidated Total
Nine months ended Sept. 30, 2006
Revenues from:
External customers	$	1,916,376	$	885,340	$	26,264	$	—		$	2,827,980
Internal customers	155		61		—		(216		)	—
Total revenue	$	1,916,531	$	885,401	$	26,264	$	(216	)	$	2,827,980
Segment net income	$	125,854	$	39,761	$	10,782	$	—		$	176,397

Nine months ended Sept. 30, 2005
Revenues from:
External customers	$	1,807,470	$	774,277	$	23,461	$	—		$	2,605,208
Internal customers	179		216		—		(395		)	—
Total revenue	$	1,807,649	$	774,493	$	23,461	$	(395	)	$	2,605,208
Segment net income	$	116,144	$	27,026	$	15,303	$	—		$	158,473

9. Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(Millions of dollars)	2006			2005			2006			2005

Net income	$	47.4		$	45.7		$	176.4		$	158.5
Other comprehensive income (loss):
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 6)	—			4.5			—			8.3
After-tax net realized gains on derivative transactions reclassified into earnings (see Note 6)	(0.4		)	(4.8		)	(1.1		)	(9.5		)
Other comprehensive loss	(0.4		)	(0.3		)	(1.1		)	(1.2		)
Comprehensive income	$	47.0		$	45.4		$	175.3		$	157.3

The accumulated other comprehensive loss in stockholder’s equity at Sept. 30, 2006 and Dec. 31, 2005, 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

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to PSCo.

Components of Net Periodic Benefit Cost

	Three months ended Sept. 30,
	2006			2005			2006			2005
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	15,406		$	15,115		$	1,659		$	1,671
Interest cost	38,854			40,246			13,234			13,765
Expected return on plan assets	(67,017		)	(70,290		)	(6,690		)	(6,425		)
Amortization of transition obligation	—			—			3,611			3,645
Amortization of prior service cost (credit)	7,424			7,509			(544		)	(545		)
Amortization of net loss	4,339			1,705			6,200			6,562
Net periodic benefit cost (credit)	(994		)	(5,715		)	17,470			18,673
Credits not recognized due to the effects of regulation	3,159			4,842			—			—
Additional cost recognized due to the effects of regulation	—			—			972			972
Net benefit cost (credit) recognized for financial reporting	$	2,165		$	(873	)	$	18,442		$	19,645

PSCo
Net periodic benefit cost	$	4,667		$	11,431		$	9,994		$	10,960
Additional cost recognized due to the effects of regulation	—			—			973			972
Net benefit cost recognized for financial reporting	$	4,667		$	11,431		$	10,967		$	11,932

	Nine months ended Sept. 30,
	2006			2005			2006			2005
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	46,220		$	45,345		$	4,975		$	5,013
Interest cost	116,560			120,738			39,704			41,295
Expected return on plan assets	(201,049		)	(210,048		)	(20,068		)	(19,275		)
Amortization of transition obligation	—			—			10,833			10,934
Amortization of prior service cost (credit)	22,272			22,527			(1,634		)	(1,634		)
Amortization of net loss	13,015			5,115			18,598			19,685
Net periodic benefit cost (credit)	(2,982		)	(16,323		)	52,408			56,018
Credits not recognized due to the effects of regulation	9,477			14,526			—			—
Additional cost recognized due to the effects of regulation	—			—			2,918			2,918
Net benefit cost (credit) recognized for financial reporting	$	6,495		$	(1,797	)	$	55,326		$	58,936

PSCo
Net periodic benefit cost	$	14,000		$	(4,036	)	$	29,982		$	32,881
Additional cost recognized due to the effects of regulation	—			—			2,918			2,918
Net benefit cost (credit) recognized for financial reporting	$	14,000		$	(4,036	)	$	32,900		$	35,799

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 of 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 consolidated 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,” “projected,” “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 inflation rates, monetary fluctuations and their impact on capital expenditures;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

• 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 (SEC), 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 subsidiaries; or security ratings;

• Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or 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 or additional competition in the markets served by PSCo;

• State, federal and foreign 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;

• 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;

• Risks associated with implementations of new technologies;

• 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; and

• The other risk factors listed from time to time by PSCo in reports filed with the SEC, including Risk Factors in Item 1A of PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2006.

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, 2005. Commodity price and interest rate risks for PSCo are mitigated due to cost-based rate regulation. At Sept. 30, 2006, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2005.

RESULTS OF OPERATIONS

PSCo’s net income was approximately $176.4 million for the first nine months of 2006, compared with approximately $158.5 million for the first nine months of 2005.

Electric Utility, Short-term Wholesale and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers, most fluctuations in these 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 or the 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. Short-term wholesale and commodity trading activities are considered part of the electric utility segment.

Margins from commodity trading activity conducted at PSCo are partially redistributed to Northern States Power Company, a Minnesota corporation, and SPS, 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, broker fees and other related costs. Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable.

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

Nine months ended Sept. 30, 2006
Electric utility revenue (excluding commodity trading)	$	1,884		$	29		$	—		$	1,913
Electric fuel and purchased power	(1,132		)	(26		)	—			(1,158		)
Commodity trading revenue	—			—			404			404
Commodity trading costs	—			—			(400		)	(400		)
Gross margin before operating expenses	$	752		$	3		$	4		$	759
Margin as a percentage of revenue	39.9		%	10.3		%	1.0		%	32.8		%

Nine months ended Sept. 30, 2005
Electric utility revenue (excluding commodity trading)	$	1,800		$	11		$	—		$	1,811
Electric fuel and purchased power	(1,051		)	(11		)	—			(1,062		)
Commodity trading revenue	—			—			387			387
Commodity trading costs	—			—			(391		)	(391		)
Gross margin before operating expenses	$	749		$	—		$	(4	)	$	745
Margin as a percentage of revenue	41.6		%	—		%	(1.0		)%	33.9		%

The following summarizes the components of the changes in base electric revenue and base electric margin for the nine months ended Sept. 30:

Base Electric Revenue

(Millions of dollars)	2006 vs. 2005

Fuel cost recovery	$	67
Quality of service plan	14
Sales growth (excluding weather impact)	7
Non-fuel rider revenue	3
Estimated impact of weather	2
Sales mix	(8		)
Other	(1		)
Total base electric revenue increase	$	84

Base Electric Margin

(Millions of dollars)	2006 vs. 2005

Quality of service plan	$	14
Sales growth (excluding weather impact)	7
Non-fuel rider revenue	3
Estimated impact of weather	2
Sales mix	(8		)
ECA incentive	(18		)
Other	3
Total base electric margin increase	$	3

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 (GCA) 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.

	Nine Months ended Sept. 30,
(Millions of dollars)	2006			2005

Natural gas utility revenue	$	885		$	774
Cost of natural gas sold and transported	(655		)	(567		)
Natural gas utility margin	$	230		$	207

The following summarizes the components of the changes in natural gas revenue and margin for the nine months ended Sept. 30:

Natural Gas Revenue

(Millions of dollars)	2006 vs. 2005

Purchased gas adjustment clause recovery	$	94
Base rate increase	13
Sales growth (excluding weather impact)	2
Estimated impact of weather on firm sales volume	(1		)
Transport and other	3
Total natural gas revenue increase	$	111

Natural Gas Margin

(Millions of dollars)	2006 vs. 2005

Base rate increase	$	13
Transportation	7
Sales growth (excluding weather impact)	2
Estimated impact of weather on firm sales volume	(1		)
Other	2
Total natural gas margin increase	$	23

Non-Fuel Operating Expense and Other Items

The following summarizes the components of the changes in other utility operating and maintenance expense for the nine months ended Sept. 30:

(Millions of dollars)	2006 vs. 2005

Higher employee benefit costs	$	12
Higher plant costs	4
Higher application and development costs	3
Higher transportation costs	1
Other	3
Total operating and maintenance expense increase	$	23

Income tax expense increased by approximately $10.1 million for the first nine months of 2006 compared with the first nine months of 2005. The effective tax rate was 25.3 percent for the first nine months of 2006, compared with 23.8 percent for the same period in 2005. The increase in tax expense and the effective tax rate was primarily due to an increase in pretax income.

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

For the quarterly period ended Sept. 30, 2006

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		(I.R.S. Employer Identification No.)
incorporation or organization)

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

Class		Outstanding at Oct 30, 2006
Common Stock, $0.01 par value		100 shares

	PART I - FINANCIAL INFORMATION
Item l.	Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 4	Controls and Procedures
	PART II - OTHER INFORMATION
Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 6.	Exhibits

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.

/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