UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

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

Commission File Number: 001-3280

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

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

1800 Larimer, Suite 1100 Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o
(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class		Outstanding at August 2, 2010
Common Stock, $0.01 par value		100 shares

Public Service Company of Colorado meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Operating revenues
Electric	$	773,621		$	588,467		$	1,497,255		$	1,185,810
Natural gas	165,894			173,494			632,177			568,615
Steam and other	7,781			7,132			20,561			17,146
Total operating revenues	947,296			769,093			2,149,993			1,771,571

Operating expenses
Electric fuel and purchased power	408,113			300,799			781,964			608,068
Cost of natural gas sold and transported	82,121			92,366			422,830			374,802
Cost of sales — steam and other	2,931			2,542			9,004			6,550
Other operating and maintenance expenses	169,025			148,600			324,718			303,490
Demand side management program expenses	33,550			23,510			67,261			49,666
Depreciation and amortization	69,217			62,915			136,183			125,462
Taxes (other than income taxes)	25,662			22,211			50,278			45,400
Total operating expenses	790,619			652,943			1,792,238			1,513,438

Operating income	156,677			116,150			357,755			258,133

Other income, net	1,326			2,112			1,882			2,981
Allowance for funds used during construction — equity	3,279			9,689			6,257			19,824

Interest charges and financing costs
Interest charges — includes other financing costs of $1,409, $1,433, $2,806 and $2,819, respectively	41,626			41,781			87,439			82,133
Allowance for funds used during construction — debt	(1,426		)	(4,367		)	(3,091		)	(9,329		)
Total interest charges and financing costs	40,200			37,414			84,348			72,804

Income before income taxes	121,082			90,537			281,546			208,134
Income taxes	43,397			29,990			119,611			69,299
Net income	$	77,685		$	60,547		$	161,935		$	138,835

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Six Months Ended June 30,
	2010			2009
Operating activities
Net income	$	161,935		$	138,835
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	138,590			127,787
Demand side management program expenses	14,562			13,063
Deferred income taxes	42,245			113,503
Amortization of investment tax credits	(1,168		)	(1,248		)
Allowance for equity funds used during construction	(6,257		)	(19,824		)
Net realized and unrealized hedging and derivative transactions	(9,697		)	42,588
Changes in operating assets and liabilities:
Accounts receivable	46,213			78,280
Accrued unbilled revenues	98,842			191,712
Recoverable purchased natural gas and electric energy costs	11,512			(41,861		)
Inventories	56,489			60,601
Prepayments and other	47,588			3,814
Accounts payable	(137,259		)	(179,394		)
Deferred electric energy costs	(26,524		)	(95,856		)
Net regulatory assets and liabilities	31,583			8,290
Other current liabilities	(6,901		)	(26,608		)
Change in other noncurrent assets	(1,650		)	6,325
Change in other noncurrent liabilities	(16,224		)	(103,387		)
Net cash provided by operating activities	443,879			316,620

Investing activities
Utility capital/construction expenditures	(222,564		)	(306,216		)
Allowance for equity funds used during construction	6,257			19,824
Investments in utility money pool	(347,200		)	(60,200		)
Repayments from utility money pool	268,200			22,200
Net cash used in investing activities	(295,307		)	(324,392		)

Financing activities
Repayment of short-term borrowings, net	(95,000		)	(40,000		)
Proceeds from issuance of long-term debt	—			394,844
Repayment of long-term debt, including reacquisition premiums	—			(756		)
Borrowings under utility money pool arrangement	184,900			530,000
Repayments under utility money pool arrangement	(268,900		)	(571,000		)
Capital contributions from parent	137,791			40,417
Dividends paid to parent	(132,477		)	(134,233		)
Net cash (used in) provided by financing activities	(173,686		)	219,272

Net (decrease) increase in cash and cash equivalents	(25,114		)	211,500
Cash and cash equivalents at beginning of period	33,429			11,198
Cash and cash equivalents at end of period	$	8,315		$	222,698

Supplemental disclosure of cash flow information:
Cash paid for interest, net of amounts capitalized	$	(78,547	)	$	(66,949	)
Cash (paid) received for income taxes, net	(11,318		)	5,284
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	15,272		$	17,327

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	June 30, 2010		Dec. 31, 2009
Assets
Current assets
Cash and cash equivalents	$	8,315	$	33,429
Accounts receivable, net	284,219		330,279
Accounts receivable from affiliates	38,533		33,396
Investments in utility money pool arrangement	79,000		—
Accrued unbilled revenues	215,111		313,953
Recoverable purchased natural gas and electric energy costs	13,645		25,157
Inventories	197,158		253,648
Deferred income taxes	79,003		81,980
Derivative instruments valuation	15,745		28,704
Prepayments and other	11,380		58,968
Total current assets	942,109		1,159,514

Property, plant and equipment, net	8,224,278		8,104,841

Other assets
Regulatory assets	821,953		827,311
Derivative instruments valuation	82,246		104,664
Other	52,189		47,175
Total other assets	956,388		979,150
Total assets	$	10,122,775	$	10,243,505

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	5,453	$	3,964
Short-term debt	—		95,000
Borrowings under utility money pool arrangement	—		84,000
Accounts payable	302,600		422,276
Accounts payable to affiliates	25,115		40,758
Deferred electric energy costs	38,028		64,552
Taxes accrued	66,779		80,303
Dividends payable to parent	66,729		65,822
Derivative instruments valuation	24,255		18,285
Accrued interest.	47,296		47,300
Other	102,475		67,692
Total current liabilities	678,730		989,952

Deferred credits and other liabilities
Deferred income taxes	1,488,168		1,447,143
Deferred investment tax credits	48,863		50,031
Regulatory liabilities	496,396		510,491
Pension and employee benefit obligations	246,618		257,881
Customer advances	256,796		271,171
Derivative instruments valuation	44,437		49,587
Asset retirement obligations	67,242		65,160
Other	56,854		31,287
Total deferred credits and other liabilities	2,705,374		2,682,751

Commitments and contingent liabilities
Capitalization
Long-term debt	2,826,911		2,824,988
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares	—		—
Additional paid-in capital	3,133,261		2,995,470
Retained earnings	770,795		742,243
Accumulated other comprehensive income	7,704		8,101
Total common stockholder’s equity	3,911,760		3,745,814
Total liabilities and equity	$	10,122,775	$	10,243,505

See Notes to Consolidated Financial Statements

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3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2010			Dec. 31, 2009
Accounts receivable, net
Accounts receivable	$	307,598		$	354,428
Less allowance for bad debts	(23,379		)	(24,149		)
	$	284,219		$	330,279
Inventories
Materials and supplies	$	46,461		$	45,809
Fuel	84,789			96,964
Natural gas	65,908			110,875
	$	197,158		$	253,648
Property, plant and equipment, net
Electric plant	$	8,570,102		$	7,635,325
Natural gas plant	2,183,640			2,133,116
Common and other property	766,657			731,511
Construction work in progress	250,896			1,038,013
Total property, plant and equipment	11,771,295			11,537,965
Less accumulated depreciation	(3,547,017		)	(3,433,124		)
	$	8,224,278		$	8,104,841

4. Income Taxes

Corporate Owned Life Insurance (COLI) — In 2007, Xcel Energy and the U. S. government settled an ongoing dispute regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. These COLI policies were owned and managed by P.S.R. Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. Xcel Energy paid the U. S. government a total of $64.4 million in settlement of the U. S. government’s claims for tax, penalty, and interest for tax years 1993 through 2007. Xcel Energy surrendered the policies to its insurer on Oct. 31, 2007, without recognizing a taxable gain. As a result of the settlement, the lawsuit filed by Xcel Energy in the United States District Court has been dismissed and the Tax Court proceedings are in the process of being dismissed.

As part of the Tax Court proceedings, during the first quarter of 2010, Xcel Energy and the Internal Revenue Service (IRS) reached an agreement in principle after a comprehensive financial reconciliation of Xcel Energy, dating back to tax year 1993. Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $10 million (including $7.7 million tax expense and $2.3 million interest expense, net of tax). Xcel Energy anticipates that the Tax Court proceedings will be dismissed in 2010.

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, PSCo is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.

As a result, PSCo expensed approximately $9.9 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. PSCo does not expect the $9.9 million of additional tax expense to recur in future periods. However, the 2010 effective tax rate (ETR) will increase due to additional tax expense of approximately $2.0 million associated with current year retiree health care accruals.

Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. During the first quarter of 2010, the IRS completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expires on Aug. 28, 2010. The IRS audit of tax years 2008 and 2009 is expected to begin during the fourth quarter of 2010.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2010, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

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Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	June 30, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	1.1	$	1.0
Unrecognized tax benefit - Temporary tax positions	6.4		6.2
Unrecognized tax benefit balance	$	7.5	$	7.2

The unrecognized tax benefit balance was reduced by the tax benefits associated with net operating loss (NOL) and tax credit carry forwards. The amounts of tax benefits associated with NOL and tax credit carryforwards were as follows:

(Millions of Dollars)	June 30, 2010			Dec. 31, 2009
Tax benefits associated with NOL and tax credit carryforwards	$	(3.9	)	$	(4.0	)

The increase in the unrecognized tax benefit balance of $0.5 million from March 31, 2010 to June 30, 2010 and $0.3 million from Dec. 31, 2009 to June 30, 2010 was due to recently provided guidance pertaining to plant-related uncertain tax positions, offset by the addition of uncertain tax positions related to ongoing activity. PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months when the IRS and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 14 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending and Recently Concluded Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

Base Rate

PSCo 2010 Electric Rate Case — In December 2009, the CPUC approved a rate increase of approximately $128.3 million; however, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo’s proposal to phase in the approved electric rate increase to reflect the actual cost of service. Under the plan, the following increases will be implemented:

· A rate increase of $67 million was implemented on Jan. 1, 2010. The adjustments to the rate increase, because of the delay of the in-service date of Comanche Unit 3, include reduced operations and maintenance expense (O&M), property taxes, the impact of a delay in changes to jurisdictional allocators and depreciation expenses;

· Base rates increased to recover $121 million annually, on May 14, 2010 when Comanche Unit 3 went into service; and

· Finally, base rates will increase to recover $128.3 million annually on Jan. 1, 2011 to reflect 2011 property taxes.

Several parties, including PSCo and the Office of Consumer Counsel (OCC), filed motions for reconsideration. On April 19, 2010, the CPUC granted PSCo’s request to not include long-term debt interest in the working capital calculation, which increases the revenue deficiency, recovered under the order by approximately $2.2 million, and denied all other requests for reconsideration.

Comanche Unit 3 went into service in May 2010, and the CPUC allowed both the step change for Comanche Unit 3 in-service and the increase to reflect the debt interest on working capital.

A second phase of the rate case addressed changes to rate design. The new rates approved by the CPUC went into effect on June 1, 2010. In this phase of the proceeding, the CPUC approved tiered summer rates for residential customers and seasonally differentiated rates for other customer classes. The CPUC also approved a low-income pilot program similar to the previously approved gas low-income pilot program.

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Transmission Cost Adjustment (TCA) Rider — In April 2010, PSCo filed a TCA rider, to adjust to the amounts recovered in the rider based on the outcome of the 2010 rate case. The filing reduced rates by $2.3 million, effective June 1, 2010. The new TCA rider reflects actual 13-month average transmission plant in service and year-end transmission construction work in progress (CWIP) account balances for 2009, as compared to the amount of transmission costs included in PSCo’s last rate case.

Unreasonable Rates for Natural Gas Formal Complaint — In July 2009, the trial advocacy staff of the CPUC proposed a complaint against PSCo for unreasonable rates for natural gas service associated with earnings in excess of PSCo’s authorized return that occurred in 2008. In January 2010, the CPUC opened a proceeding and assigned this matter to an ALJ.

The ALJ recommended approval of an unopposed settlement of the case on June 14, 2010 and vacated the schedule in the docket. The settlement, provided that no adjustments to current rates would be made, PSCo would file a gas rate case before the end of 2010. In that case, PSCo would propose to remove recovery on gas in storage from base rates to an adjustment clause.

Renewable Energy Credit (REC) Sharing Settlement — In August 2009, PSCo filed an application seeking approval of treatment of margins associated with certain sales of Colorado RECs bundled with energy into California. In January 2010, PSCo, the OCC, the CPUC staff, the Colorado governor’s energy office and Western Resource Advocates entered into a unanimous settlement in this case. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides margins would be shared based on the following:

Margin	Customers		PSCo		Carbon Offsets
Less that $10 million	50	%	40	%	10	%
$10 million to $30 million	55		35		10
Greater than $30 million	60		30		10

Amounts designated as carbon offsets are recorded as a regulatory liability until carbon offset-related expenditures are incurred. Carbon offsets are capped at $10 million, with the remaining 10 percent going to customers after the cap is reached. The unanimous settlement also clarified that margins associated with RECs bundled with Colorado energy would be shared 20 percent to PSCo and 80 percent to customers and margins associated with sales of stand-alone renewable energy credits without energy would be credited 100 percent to customers. The CPUC approved the settlement in a written order in May 2010.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate Case — In 2009, PSCo filed a request with the FERC to increase electric rates to its firm wholesale customers by $30.7 million based on a 12.5 percent ROE, a 58 percent equity ratio and a rate base of $315 million. In June and July 2010, PSCo filed blackbox settlements with all of its wholesale customers except for Intermountain Rural Electric Association at the FERC. Under the terms of that settlement, PSCo would increase rates on an annual basis by $17.0 million for these customers, effective July 7, 2010. In addition, on Jan. 1, 2011, an additional step rate increase of $1.0 million will be implemented for property taxes associated with Comanche Unit 3. The terms of the settlement provide for lower depreciation expense than requested and for certain capacity costs to be recovered through the fuel clause until those contracts expire. A decision by the FERC on the settlements is expected by the end of 2010.

6. Commitments and Contingent Liabilities

Except to the extent noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q the circumstances set forth in Notes 14 and 15 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2009, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.

Commitments

Variable Interest Entities — Effective Jan. 1, 2010, PSCo adopted new guidance on consolidation of variable interest entities contained in ASC 810 Consolidation. The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

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Purchased Power Agreements — PSCo has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

PSCo has various pay-for-performance contracts with expiration dates through the year 2034. In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

Certain natural gas fueled purchased power agreements that either reimburse the independent power producing entities for fuel costs, or contain tolling arrangements under which PSCo procures the fuel required to produce the energy it purchases, have been determined to be variable interest entities.

PSCo has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over operations and maintenance, historical and estimated future fuel and electricity prices, and financing activities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. As of June 30, 2010 and Dec. 31, 2009, PSCo had approximately 2,921 megawatts (MW) of capacity under long term purchased power agreements with entities that have been determined to be variable interest entities.

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 believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) 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.

Site Remediation — PSCo must pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former manufactured gas plants operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent hazardous materials and wastes. At June 30, 2010, the liability for the cost of remediating these sites was estimated to be $0.8 million, of which $0.3 million was considered to be a current liability.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. PSCo has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations in Note 15 of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2009. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

Colorado Clean Air-Clean Jobs Act — The Colorado Clean Air-Clean Jobs Act (the Act) was signed into law on April 19, 2010. The Act establishes a timeline and regulatory framework for rate-regulated utilities in Colorado to develop a plan to potentially retrofit, retire or replace 900 MW or more of aging coal-fired electric generating capacity. The plan must result in a reduction of 70 to 80 percent in nitrogen oxide (NOx) emissions from affected coal-fired power plants by 2018 or sooner to meet current and reasonably foreseeable Clean Air Act (CAA) emission reduction mandates.

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Under the emission reduction plan, PSCo may retrofit its existing coal-fired plants with emission controls or retire and replace the plants with natural gas-fired generation or other low emitting resources. The Act specifically requires PSCo to study the early retirement of up to 900 MW of existing coal-fired capacity, but does not require any retirement unless, among other things, the retirement can be accomplished at a reasonable cost while protecting system reliability. PSCo must submit its plan to the CPUC by Aug. 15, 2010 and the CPUC must act on the plan by Dec. 15, 2010.

Pursuant to the Act, PSCo is entitled to fully recover the costs that it prudently incurs in executing an approved emission reduction plan and is allowed a return on CWIP on plan investments. In addition, if early action is taken to retire or convert units to natural gas, and PSCo shows that the costs of the plan would contribute to any earnings deficiency, additional relief, including a more comprehensive rider to recover other plant costs such as depreciation and O&M expense, or a multi-year rate plan are allowed. The Act also makes interim rates permissible in Colorado, starting Jan. 1, 2012. Additional information regarding the Colorado Clean Air-Clean Jobs Act is presented in the Management’s Discussion of Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Continuing Operations, Public Utility Regulation section.

Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Rulemaking — On Dec. 7, 2009, in response to the U. S. Supreme Court’s decision in Massachusetts v. EPA, 549 U. S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere. This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty vehicles. The EPA finalized GHG efficiency standards for light duty vehicles in spring of 2010 and has promulgated permitting requirements for GHGs for large new and modified stationary sources, such as power plants. These regulations will become applicable in 2011.

Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. In February 2008, the U. S. Court of Appeals for the District of Columbia vacated CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize Maximum Achievable Control Technology (MACT) emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace CAMR. PSCo anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter.

Colorado Mercury Regulation — Colorado’s mercury regulations require mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by 2012 and other specified units by 2014. The expected cost estimate for the Pawnee Generating Station is $2.3 million for capital costs with an annual estimate of $1.4 million for sorbent expense. PSCo is evaluating the emission controls required to meet the state rule for the remaining units and is currently unable to provide a total capital cost estimate.

Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Xcel Energy generating facilities in several states will be subject to BART requirements.

States are required to identify the facilities that will have to reduce sulfur dioxide, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities. In May 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal.

PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2015. Colorado’s BART state implementation plan (SIP) has been submitted to the EPA for approval. The Colorado Air Pollution Control Division (CAPCD) is currently analyzing what types of additional NOx controls may be necessary to meet reasonable progress goals for Colorado’s Class I areas, the new ozone standard, and Rocky Mountain National Park nitrogen deposition reduction goals. The CAPCD has indicated that it expects to submit a Regional Haze/Reasonable Further Progress SIP to the EPA in early 2011. PSCo anticipates that for those plants included in the Clean Air-Clean Jobs Act’s emission reduction plan, the plan will satisfy regional haze requirements.

In March 2010, two environmental groups petitioned the U. S. Department of Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. Four PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege that the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

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Federal Clean Water Act — The federal Clean Water Act (CWA) requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA challenging the phase II rulemaking. In April 2009, the U. S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA. The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules. Until the EPA fully responds, the rule’s compliance requirements and associated deadlines will remain unknown. As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

Proposed Coal Ash Regulation — In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as a special waste (subject to many of the requirements for hazardous waste) or as a solid (nonhazardous) waste. Coal ash is currently exempt from hazardous waste regulation. The EPA’s proposal would result in more comprehensive and expensive requirements related to management and disposal of coal ash. There is a 90-day comment deadline to submit comments on the rule, but requests for extension of time to submit comments have been submitted to the EPA. The EPA is also seeking comment on what regulations are appropriate for the beneficial reuse of coal ash. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

PSCo Notice of Violation (NOV) — In July 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Station 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 CAA and NSR process. PSCo 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 disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

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.

Environmental Litigation

Carbon Dioxide (CO2) Emissions Lawsuit — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U. S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of PSCo, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds. On appeal in September 2009, the U. S. Court of Appeals for the Second Circuit reversed the lower court decision. Defendants anticipate filing a petition for review with the U. S. Supreme Court.

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of PSCo, received notice of a purported class action lawsuit filed in U. S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege 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. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. Plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Fifth Circuit. In October 2009, the U. S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court. A subsequent petition by defendants, including Xcel Energy, for en banc review was granted. On May 28, 2010, the U. S. Court of Appeals for the Fifth Circuit ruled that it lacked an en banc quorum of nine active members to hear the case. It dismissed the appeal, which resulted in the reinstatement of the district court’s opinion dismissing the case.

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Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U. S. District Court for the Northern District of California against Xcel Energy, the parent company of PSCo, and 23 other utilities, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008. In October 2009, the U. S. District Court dismissed the lawsuit on constitutional grounds. In November 2009, plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Ninth Circuit. It is unknown when the Ninth Circuit will render a final opinion.

Comanche Unit 3 CAA Lawsuit — In July 2009, WildEarth Guardians (WEG) filed a lawsuit in the U. S. District Court in Colorado against PSCo alleging that PSCo violated the CAA by constructing Comanche Unit 3 without a final MACT determination from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD). PSCo disputes these claims and filed a motion to dismiss the suit. Comanche Unit 3 was constructed with state-of-the-art emission controls and pursuant to a valid air permit issued by the APCD. In January 2010, WEG sought to enjoin PSCo from constructing, modifying, or operating Comanche Unit 3 prior to receiving a final MACT determination. The court denied WEG’s request for a temporary restraining order on Jan. 26, 2010. In March 2010, the court partially granted and partially denied PSCo’s motion to dismiss. The court requested additional briefing on certain issues related to the MACT determination. Briefing has now been completed, and the court is expected to issue a final ruling in due course.

Cherokee Opacity Lawsuit — In August 2009, WEG filed a lawsuit alleging that PSCo had violated the CAA through alleged opacity monitor downtime, as well as by allegedly exceeding opacity limits on 49 occasions over a five-year period at Cherokee Station. In September 2009, PSCo filed a motion to dismiss the lawsuit and argued that opacity monitor downtime is permitted by law. Cherokee’s opacity monitors were operating 98.4 percent of the time during the period in question. When the monitors were not operating, it was for allowed activities, such as calibration, quality control or repair. On April 16, 2010, the court denied PSCo’s motion to dismiss, holding that whether the opacity monitor downtime is permitted is a question of fact that cannot be resolved in a motion to dismiss. PSCo will continue to vigorously defend the lawsuit.

Employment, Tort and Commercial Litigation

Qwest vs. Xcel Energy Inc. — In 2004, an employee of PSCo was seriously injured when a pole owned by Qwest malfunctioned. In September 2005, the employee commenced an action against Qwest in Colorado state court in Denver. In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo. In May 2007, the matter was tried and the jury found Qwest solely liable for the accident and this determination resulted in an award of damages in the amount of approximately $90 million. In April 2009, the Colorado Court of Appeals affirmed the jury verdict insofar as it relates to claims asserted by Qwest against PSCo. Qwest filed a petition for rehearing with the Colorado Supreme Court in June 2009. In February 2010, the Colorado Supreme Court agreed to review the Court of Appeals’ decision as to the punitive damages issue but will not review the Court of Appeals’ decision as it relates to PSCo. It is unknown when the Colorado Supreme Court will render a decision.

Mallon vs. Xcel Energy Inc. — In August 2007, Xcel Energy, PSCo and PSRI (Plaintiffs) commenced a lawsuit in Colorado state court against Theodore Mallon and TransFinancial Corporation seeking damages for, among other things, breach of contract and breach of fiduciary duties associated with the sale of COLI policies. In May 2008, Plaintiffs filed an amended complaint that, among other things, adds Provident Life & Accident Insurance Company (Provident) as a defendant and asserts claims for breach of contract, unjust enrichment and fraudulent concealment against the insurance company. In November 2009, Plaintiffs reached a settlement with Mallon and TransFinancial Corporation, where Mallon agreed to pay Plaintiffs a specified amount of money and the parties agreed to mutually release each other from all claims.

On July 6, 2010, Plaintiffs entered into a settlement agreement with Provident. Under the terms of the settlement, Provident and Reassure America Life Insurance Company paid Plaintiffs $25 million. Xcel Energy will record this settlement of $25 million in the third quarter of 2010. See additional information set forth in Note 15 to the consolidated financial statements in this Quarterly Report on Form 10-Q.

Cabin Creek Hydro Generating Station Accident — In October 2007, employees of RPI Coatings Inc. (RPI), a contractor retained by PSCo, were applying an epoxy coating to the inside of a penstock at PSCo’s Cabin Creek Hydro Generating Station near Georgetown, Colo. A fire occurred inside a pipe used to deliver water from a reservoir to the hydro facility. Five RPI employees were unable to exit the pipe and rescue crews confirmed their deaths. The accident was investigated by several state and federal agencies, including the federal Occupational Safety and Health Administration (OSHA) and the U. S. Chemical Safety Board and the Colorado Bureau of Investigations.

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In March 2008, OSHA proposed penalties totaling $189,900 for 22 serious violations and three willful violations arising out of the accident. In April 2008, Xcel Energy notified OSHA of its decision to contest all of the proposed citations. On May 28, 2008, the Secretary of Labor filed its complaint, and Xcel Energy subsequently filed its answer on June 17, 2008. The Court ordered this proceeding stayed until March 3, 2009 and has subsequently extended the stay until the criminal proceedings have concluded.

A lawsuit was filed in Colorado state court in Denver on behalf of four of the deceased workers and four of the injured workers (Foster, et. al. v. PSCo, et. al.). PSCo and Xcel Energy were named as defendants in that case, along with RPI Coatings and related companies and the two other contractors who also performed work in connection with the relining project at Cabin Creek. A second lawsuit (Ledbetter et. al vs. PSCo et. al) was also filed in Colorado state court in Denver on behalf of three employees allegedly injured in the accident. A third lawsuit was filed on behalf of one of the deceased RPI workers in the California state court (Aguirre v. RPI, et. al.), naming PSCo, RPI, and the two other contractors as defendants. The court subsequently dismissed the Aguirre lawsuit. Settlements were subsequently reached in all three lawsuits. These confidential settlements did not have a material effect on the financial statements of Xcel Energy or its subsidiaries.

On Aug. 28, 2009, the U. S. Government announced that Xcel Energy and PSCo have been charged with five misdemeanor counts in federal court in Colorado for violation of an OSHA regulation related to the accident at Cabin Creek in October 2007. RPI Coatings, the contractor performing the work at the plant, and two individuals employed by RPI have also been indicted. On Sept. 22, 2009, both Xcel Energy and PSCo entered a not guilty plea, and both will vigorously defend against these charges. In December 2009, Xcel Energy and PSCo filed two separate motions to dismiss. On March 29, 2010, the court issued an order denying both motions. No trial date has yet been set.

Stone & Webster, Inc. vs. PSCo — In July 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal fired plant. Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleges, among other things, that PSCo mismanaged the construction of Comanche Unit 3. Shaw further claims that this alleged mismanagement caused delays and damages in excess of $55 million. The complaint also alleges that Xcel Energy and related entities guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement. Shaw alleges that it will not receive the $10 million to which it is entitled. Accordingly, Shaw seeks an amount up to $10 million relating to the 2003 settlement agreement. PSCo denies these allegations and believes the claims are without merit. PSCo filed an answer and counterclaim in August 2009, denying the allegations in the complaint and alleging that Shaw has failed to discharge its contractual obligations and has caused delays, and that PSCo is entitled to liquidated damages and excess costs incurred. In June 2010, PSCo exercised its contractual right to draw on Shaw’s letter of credit in the total amount of approximately $29.6 million. Trial is scheduled for Oct. 18, 2010.

Connie DeWeese vs. PSCo — In November 2008, there was an explosion in Pueblo, Colo., which destroyed a tavern and a neighboring store. The explosion killed one person and injured seven people. The Pueblo Fire Department and the Federal Bureau of Alcohol, Tobacco and Firearms have determined a natural gas leak from a pipeline under the street led to the explosion. In February 2010, a wrongful death/personal injury lawsuit was filed in Colorado District Court in Pueblo, Colorado against PSCo and the City of Pueblo by several parties that were allegedly injured, as a result of this explosion. The plaintiffs are also alleging economic and noneconomic damages. The lawsuit alleges that the accident occurred as a result of PSCo’s negligence. A related lawsuit was filed in March 2010 by Seneca Insurance Company, which insured Branch Inn, LLC and Branch Inn Enterprises, LLC. The Plaintiffs are alleging destruction of the building and disruption of the business. Both lawsuits allege that the accident occurred as a result of PSCo’s negligence. PSCo denies liability for this accident. The cases have been consolidated. In June 2010, the court granted, in part, PSCo’s motion to dismiss certain of plaintiffs’ claims related to, among other things, strict liability. In July 2010, a third related lawsuit was filed by Truck Insurance Exchange against PSCo and the City of Pueblo to recover damages allegedly paid by the plaintiff insurance company to its insured as a result of the explosion. PSCo will file a response denying liability in due course.

7. Short-Term Borrowings and Other Financing Instruments

Commercial Paper — The following table presents commercial paper outstanding for PSCo:

(Millions of Dollars)	June 30, 2010			Dec. 31, 2009
Commercial paper outstanding	$	—		$	95
Weighted average interest rate	N/A		%	0.35		%
Total commercial paper available for issuance	$	675		$	675

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Money Pool — Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other. The holding company may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in the holding company.

The following table presents the money pool investments (borrowings) for PSCo:

(Millions of Dollars)	June 30, 2010			Dec. 31, 2009
Money pool investments (borrowings)	$	79		$	(84	)
Weighted average interest rate	0.40		%	0.36		%
Money pool borrowing limit	$	250		$	250

8. Derivative Instruments and Fair Value Measurements

PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. PSCo’s risk management policy allows management to conduct the marketing activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

Interest Rate Derivatives — 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 generally designated as cash flow hedges for accounting purposes.

At June 30, 2010, accumulated other comprehensive income (OCI) related to interest rate derivatives included $1.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale, and vehicle fuel.

At June 30, 2010, PSCo had various vehicle fuel related contracts designated as cash flow hedges extending through December 2012. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the six months ended June 30, 2010.

At June 30, 2010, accumulated OCI related to commodity derivative cash flow hedges included $0.7 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in income subject to applicable customer margin-sharing mechanisms.

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The following table details the gross notional amounts of commodity forwards at June 30, 2010 and Dec. 31, 2009:

(Amounts in Thousands) (a)	June 30, 2010	Dec. 31, 2009
Megawatt hours (MWh) of electricity	5,222	3,559
MMBtu of natural gas	44,994	45,352
Gallons of vehicle fuel	870	1,559

(a) Amounts are not reflective of net positions in the underlying commodities.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated OCI, included as a component of common stockholder’s equity, is detailed in the following table:

	Three Months Ended June 30,
(Thousands of Dollars)	2010			2009
Accumulated other comprehensive income related to cash flow hedges at April 1	$	7,993		$	7,763
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(123		)	586
After-tax net realized gains on derivative transactions reclassified into earnings	(166		)	(328		)
Accumulated other comprehensive income related to cash flow hedges at June 30	$	7,704		$	8,021

	Six Months Ended June 30,
(Thousands of Dollars)	2010			2009
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	8,101		$	7,628
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(108		)	599
After-tax net realized gains on derivative transactions reclassified into earnings	(289		)	(206		)
Accumulated other comprehensive income related to cash flow hedges at June 30	$	7,704		$	8,021

PSCo had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2010 and June 30, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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The following tables detail the impact of derivative activity during the three and six months ended June 30, 2010 and June 30, 2009, respectively, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2010
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses)
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities			Other Comprehensive Income			Regulatory Assets and Liabilities			Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(582	)(a)	$	—		$	—
Vehicle fuel and other commodity	(198		)	—			315		(c)	—			—
Total	$	(198	)	$	—		$	(267	)	$	—		$	—

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	(273	)(b)
Natural gas commodity	—			(3,723		)	—			752		(d)	—
Other	—			—			—			—			84		(b)
Total	$	—		$	(3,723	)	$	—		$	752		$	(189	)

	Six Months Ended June 30, 2010
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses)
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities			Other Comprehensive Income			Regulatory Assets and Liabilities			Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(1,158	)(a)	$	—		$	—
Vehicle fuel and other commodity	(174		)	—			692		(c)	—			—
Total	$	(174	)	$	—		$	(466	)	$	—		$	—

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	(522	)(b)
Natural gas commodity	—			(31,287		)	—			4,389		(d)	—
Other	—			—			—			—			134		(b)
Total	$	—		$	(31,287	)	$	—		$	4,389		$	(388	)

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	Three Months Ended June 30, 2009
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses)
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities			Other Comprehensive Income			Regulatory Assets and Liabilities			Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(632	)	$	—		$	(593	)(a)	$	—		$	—
Natural gas commodity	—			(417		)	—			409		(d)	—
Vehicle fuel and other commodity	944			—			695		(c)	—			—
Total	$	312		$	(417	)	$	102		$	409		$	—

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	1,134	(b)
Natural gas commodity	—			6,444			—			—			—
Total	$	—		$	6,444		$	—		$	—		$	1,134

	Six Months Ended June 30, 2009
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses)
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities			Other Comprehensive Income			Regulatory Assets and Liabilities			Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(632	)	$	—		$	(1,185	)(a)	$	—		$	—
Natural gas commodity	—			(16,098		)	—			66,109		(d)	(22,243		)(d)
Vehicle fuel and other commodity	964			—			1,486		(c)	—			—
Total	$	332		$	(16,098	)	$	301		$	66,109		$	(22,243	)

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	2,543	(b)
Natural gas commodity	—			(8,202		)	—			15		(d)	—
Total	$	—		$	(8,202	)	$	—		$	15		$	2,543

(a) Recorded to interest charges

(b) Recorded to electric operating revenues. Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(d) Recorded to cost of natural gas sold and transported; these derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate.

Credit Related Contingent Features — Contract provisions of the derivative instruments that PSCo enters into may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unable to maintain its credit ratings. If the credit ratings of PSCo were downgraded below investment grade, contracts underlying $3.4 million and $0.6 million of derivative instruments in a net liability position at June 30, 2010 and Dec. 31, 2009, respectively, would have required PSCo to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $3.4 million and $3.4 million, respectively. At June 30, 2010 and Dec. 31, 2009, there was no collateral posted on these specific contracts.

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PSCo’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2010 and Dec. 31, 2009.

Fair Value Measurements

ASC 820 Fair Value Measurements and Disclosures provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with discounted cash flow or option pricing models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reported date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Recurring Fair Value Measurements

The following table presents for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at June 30, 2010:

	June 30, 2010
	Fair Value						Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	10	$	—	$	10	$	(10	)	$	—
Other derivative instruments:
Trading commodity	1,768		12,331		298		14,397		(12,396		)	2,001
Natural gas commodity	—		117		—		117		(117		)	—
Total current derivative assets	$	1,768	$	12,458	$	298	$	14,524	$	(12,523	)	2,001
Purchased power agreements (a)												13,744
Current derivative instruments valuation												$	15,745
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	37	$	—	$	37	$	—		$	37
Other derivative instruments:
Trading commodity	—		3,592		541		4,133		(912		)	3,221
Total noncurrent derivative assets	$	—	$	3,629	$	541	$	4,170	$	(912	)	3,258
Purchased power agreements (a)												78,988
Noncurrent derivative instruments valuation												$	82,246

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	June 30, 2010
	Fair Value						Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	756	$	—	$	756	$	(10	)	$	746
Other derivative instruments:
Trading commodity	1,263		13,041		119		14,423		(13,069		)	1,354
Natural gas commodity	—		24,107		—		24,107		(7,692		)	16,415
Total current derivative liabilities	$	1,263	$	37,904	$	119	$	39,286	$	(20,771	)	18,515
Purchased power agreements (a)												5,740
Current derivative instruments valuation												$	24,255
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	—	$	2,614	$	121	$	2,735	$	(913	)	$	1,822
Natural gas commodity	—		72		—		72		—			72
Total noncurrent derivative liabilities	$	—	$	2,686	$	121	$	2,807	$	(913	)	1,894
Purchased power agreements (a)												42,543
Noncurrent derivative instruments valuation												$	44,437

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, PSCo began recording several long-term purchased power 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 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer 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 assets and liabilities.

(b) ASC 815 Derivatives and Hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between PSCo and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

PSCo recognizes transfers between levels as of the beginning of each period. No transfers occurred between levels during the three and six months ended June 30, 2010.

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The following table presents for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2009:

	Dec. 31, 2009
	Fair Value						Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Other derivative instruments:
Trading commodity	$	—	$	2,380	$	986	$	3,366	$	(2,120	)	$	1,246
Natural gas commodity	—		8,752		—		8,752		111			8,863
Total current derivative assets	$	—	$	11,132	$	986	$	12,118	$	(2,009	)	10,109
Purchased power agreements (a)												18,595
Current derivative instruments valuation												$	28,704
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	69	$	—	$	69	$	—		$	69
Other derivative instruments:
Trading commodity	—		1,514		1,535		3,049		677			3,726
Natural gas commodity	—		476		—		476		248			724
Total noncurrent derivative assets	$	—	$	2,059	$	1,535	$	3,594	$	925		4,519
Purchased power agreements (a)												100,145
Noncurrent derivative instruments valuation												$	104,664

Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	1,338	$	—	$	1,338	$	—		$	1,338
Other derivative instruments:
Trading commodity	—		3,555		834		4,389		(2,589		)	1,800
Natural gas commodity	—		6,090		—		6,090		111			6,201
Total current derivative liabilities	$	—	$	10,983	$	834	$	11,817	$	(2,478	)	9,339
Purchased power agreements (a)												8,946
Current derivative instruments valuation												$	18,285
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	—	$	489	$	883	$	1,372	$	676		$	2,048
Natural gas commodity	—		302		—		302		248			550
Total noncurrent derivative liabilities	$	—	$	791	$	883	$	1,674	$	924		2,598
Purchased power agreements (a)												46,989
Noncurrent derivative instruments valuation												$	49,587

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The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options. Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers.

PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

The following tables present the changes in Level 3 recurring fair value measurements for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended June 30,
(Thousands of Dollars)	2010			2009
Balance at April 1	$	331		$	2,148
Purchases and settlements, net	(113		)	(819		)
Transfers into Level 3	—			588
Gains recognized in earnings	381			291
Gains recognized as regulatory assets and liabilities	—			465
Balance at June 30	$	599		$	2,673

	Six Months Ended June 30,
(Thousands of Dollars)	2010			2009
Balance at Jan. 1	$	804		$	(26	)
Purchases and settlements, net	(263		)	(1,172		)
Transfers into Level 3	—			588
Gains recognized in earnings	58			2,755
Gains recognized as regulatory assets and liabilities	—			528
Balance at June 30	$	599		$	2,673

Gains on Level 3 commodity derivatives recognized in earnings for the three months ended June 30, 2010, include $0.3 million of net unrealized gains relating to commodity derivatives held at June 30, 2010. Gains on Level 3 commodity derivatives recognized in earnings for the three and six months ended June 30, 2009, include $0.3 million and $2.8 million of net unrealized gains relating to commodity derivatives held at June 30, 2009. Gains on Level 3 commodity derivatives recognized in earnings for the six months ended June 30, 2010 included an immaterial amount of unrealized gains relating to commodity derivatives held at June 30, 2010. Realized and unrealized gains and losses on commodity trading activities are included in electric revenues. Realized and unrealized gains and losses on short-term wholesale activities reflect the impact of regulatory recovery and are deferred as regulatory assets and liabilities.

9. Financial Instruments

The estimated fair values of PSCo’s recorded financial instruments are as follows:

	June 30, 2010				Dec. 31, 2009
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Other investments	$	8	$	8	$	8	$	8
Long-term debt, including current portion	2,832,364		3,206,425		2,828,952		3,050,249

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts. The fair value of PSCo’s other investments is estimated based on quoted market prices for those or similar investments. The fair value of PSCo’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

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The fair value estimates presented are based on information available to management as of June 30, 2010 and Dec. 31, 2009. These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date and current estimates of fair values may differ significantly.

Letters of Credit — PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, 2010 and Dec. 31, 2009, there were $4.5 million and $4.6 million of letters of credit outstanding, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

10. Other Income, Net

Other income (expense), net, consisted of the following:

	Three Months Ended June 30,					Six Months Ended June 30,
(Thousands of Dollars)	2010		2009			2010			2009
Interest income	$	741	$	600		$	1,119		$	1,067
Other nonoperating income	428		2,099			859			2,454
Insurance policy (expense) income	157		(587		)	(96		)	(463		)
Other nonoperating expense	—		—			—			(77		)
Other income, net	$	1,326	$	2,112		$	1,882		$	2,981

11. Segment Information

PSCo has two reportable segments: regulated electric and regulated natural gas. Commodity trading operations are not a reportable segment and are included in the regulated electric segment. All other revenues primarily include steam revenue, appliance repair services and nonutility real estate activities.

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Three Months Ended June 30, 2010
Operating revenues from external customers	$	773,621	$	165,894	$	7,781	$	—		$	947,296
Intersegment revenues	55		32		—		(87		)	—
Total revenues	$	773,676	$	165,926	$	7,781	$	(87	)	$	947,296
Net income	$	65,369	$	10,539	$	1,777	$	—		$	77,685

Three Months Ended June 30, 2009
Operating revenues from external customers	$	588,467	$	173,494	$	7,132	$	—		$	769,093
Intersegment revenues	53		16		—		(69		)	—
Total revenues	$	588,520	$	173,510	$	7,132	$	(69	)	$	769,093
Net income	$	44,749	$	11,616	$	4,182	$	—		$	60,547

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
Six Months Ended June 30, 2010
Operating revenues from external customers	$	1,497,255	$	632,177	$	20,561		$	—		$	2,149,993
Intersegment revenues	132		104		—			(236		)	—
Total revenues	$	1,497,387	$	632,281	$	20,561		$	(236	)	$	2,149,993
Net income (loss)	$	122,723	$	45,213	$	(6,001	)	$	—		$	161,935

Six Months Ended June 30, 2009
Operating revenues from external customers	$	1,185,810	$	568,615	$	17,146		$	—		$	1,771,571
Intersegment revenues	146		47		—			(193		)	—
Total revenues	$	1,185,956	$	568,662	$	17,146		$	(193	)	$	1,771,571
Net income	$	87,060	$	42,855	$	8,920		$	—		$	138,835

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12. Comprehensive Income

The components of total comprehensive income are shown below:

	Three Months Ended June 30,
(Thousands of Dollars)	2010			2009
Net income	$	77,685		$	60,547
Other comprehensive (loss) income:
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(123		)	586
After-tax net realized gains on derivative transactions reclassified into earnings	(166		)	(328		)
Other comprehensive (loss) income	(289		)	258
Comprehensive income	$	77,396		$	60,805

	Six Months Ended June 30,
(Thousands of Dollars)	2010			2009
Net income	$	161,935		$	138,835
Other comprehensive (loss) income:
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(108		)	599
After-tax net realized gains on derivative transactions reclassified into earnings	(289		)	(206		)
Other comprehensive (loss) income	(397		)	393
Comprehensive income	$	161,538		$	139,228

13. 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 June 30,
	2010			2009			2010			2009
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	18,956		$	16,744		$	965		$	1,057
Interest cost	41,853			43,046			10,861			13,050
Expected return on plan assets	(58,035		)	(64,909		)	(7,131		)	(5,993		)
Amortization of transition obligation	—			—			3,611			3,726
Amortization of prior service cost (credit)	5,164			6,154			(1,233		)	(711		)
Amortization of net loss	13,134			3,299			3,113			4,779
Net periodic pension cost	21,072			4,334			10,186			15,908
Costs not recognized and additional cost recognized due to the effects of regulation	(6,314		)	(959		)	973			973
Net benefit cost recognized for financial reporting	$	14,758		$	3,375		$	11,159		$	16,881

PSCo:
Net periodic benefit cost	$	4,329		$	3,163		$	5,640		$	10,565
Additional cost recognized due to the effects of regulation	—			—			973			973
Net benefit cost recognized for financial reporting	$	4,329		$	3,163		$	6,613		$	11,538

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	Six Months Ended June 30,
	2010			2009			2010			2009
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	36,574		$	32,730		$	2,003		$	2,333
Interest cost	82,505			84,895			21,390			25,206
Expected return on plan assets	(116,159		)	(128,269		)	(14,265		)	(11,388		)
Amortization of transition obligation	—			—			7,222			7,222
Amortization of prior service cost (credit)	10,328			12,309			(2,466		)	(1,363		)
Amortization of net loss	24,158			6,228			5,822			9,665
Net periodic pension cost	37,406			7,893			19,706			31,675
Costs not recognized and additional cost recognized due to the effects of regulation	(13,640		)	(1,446		)	1,946			1,946
Net benefit cost recognized for financial reporting	$	23,766		$	6,447		$	21,652		$	33,621

PSCo:
Net periodic benefit cost	$	7,652		$	6,924		$	11,153		$	20,139
Additional cost recognized due to the effects of regulation	—			—			1,946			1,946
Net benefit cost recognized for financial reporting	$	7,652		$	6,924		$	13,099		$	22,085

14. PSCo Agreement to Acquire Assets from Calpine Development Holdings, Inc.

In April 2010, PSCo reached an agreement with Riverside Energy Center, LLC and Calpine Development Holdings, Inc. to purchase the Rocky Mountain Energy Center and Blue Spruce Energy Center natural gas generation assets for $739 million. The acquisition is expected to close in December 2010.

The Rocky Mountain Energy Center is a 621 MW combined cycle natural gas-fired power plant that began commercial operations in 2004. The Blue Spruce Energy Center is a 310 MW simple cycle natural gas-fired power plant that began commercial operations in 2003. Both power plants currently provide energy and capacity to PSCo under power purchase agreements, which were set to expire in 2013 and 2014.

The acquisition developed from the PSCo 2007 resource plan in which the assets were offered as part of the CPUC competitive bidding process. The offer was the least cost option for thermal resources to be acquired under the plan.

The acquisition is subject to federal and state regulatory approvals including approval of the proposed recovery of costs. In June 2010, the Federal Trade Commission provided notice of the early termination of the waiting period under Hart-Scott-Rodino. In July 2010, FERC issued an order approving the acquisition. The parties must obtain approval of the Federal Communications Commission for transfer of radio licenses associated with the plants, which is the remaining federal regulatory approval. The procedural schedule for state regulatory approval by the CPUC is as follows:

· Intervenor answer testimony due Aug. 9, 2010;

· Rebuttal and cross-answer testimony due Sept. 3, 2010;

· Hearings are Sept. 20 through Sept. 22, 2010;

· Deliberations due Oct. 18, 2010;

· Initial CPUC decision by Oct. 29, 2010; and

· Final decision expected on or before Dec. 1, 2010.

15. Subsequent Event — Settlement with Provident Life & Accident Insurance Company

In July 2010, Xcel Energy, PSCo and PSRI (Xcel Energy) entered into a full and final settlement agreement with Provident related to all claims asserted by Xcel Energy against Provident in a lawsuit associated with Xcel Energy’s discontinued COLI program. Under the terms of the settlement, Xcel Energy was paid $25 million by Provident and Reassure America Life Insurance Company. Xcel Energy will record this settlement of $25 million in the third quarter of 2010.

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Electric Revenues and Margin

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, fluctuations in these costs do not materially affect electric margin. The following tables detail the electric revenues and margin:

	Six Months Ended June 30,
(Millions of Dollars)	2010			2009
Electric revenues	$	1,497		$	1,186
Electric fuel and purchased power	(782		)	(608		)
Electric margin	$	715		$	578

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

Electric Revenues

(Millions of Dollars)	2010 vs. 2009
Fuel and purchased power cost recovery	$	153
Retail rate increase	100
Trading	22
DSM revenue and incentive (partially offset by expenses)	14
Estimated impact of weather	8
Retail sales increase (excluding weather impact)	6
Other, net	8
Total increase in electric revenues	$	311

Electric Margin

(Millions of Dollars)	2010 vs. 2009
Retail rate increase	$	100
DSM revenue and incentive (partially offset by expenses)	14
Estimated impact of weather	8
Retail sales increase (excluding weather impact)	6
Firm wholesale	6
Trading	1
Other, net	2
Total increase in electric margin	$	137

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. PSCo has a 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. The following tables detail the natural gas revenues and margin:

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

	Six Months Ended June 30,
(Millions of Dollars)	2010			2009
Natural gas revenues	$	632		$	569
Cost of natural gas sold and transported	(423		)	(375		)
Natural gas margin	$	209		$	194

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Natural Gas Revenues

(Millions of Dollars)	2010 vs. 2009
Purchased natural gas cost recovery	$	48
Estimated impact of weather	9
DSM revenue and incentive (partially offset by expenses)	2
Other, net	4
Total increase in natural gas revenues	$	63

Natural Gas Margin

(Millions of Dollars)	2010 vs. 2009
Estimated impact of weather	$	9
DSM revenue and incentive (partially offset by expenses)	2
Other, net	4
Total increase in natural gas margin	$	15

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses increased by approximately $21.2 million, or 7.0 percent, for the first six months of 2010, compared with the first six months of 2009. The following summarizes the components of the changes for the six months ended June 30:

(Millions of Dollars)	2010 vs. 2009
Higher plant generation costs	$	9
Higher labor costs	3
Higher contract labor costs	3
Higher information technology costs	3
Lower employee benefit costs	(3		)
Other, net	6
Total increase in other operating and maintenance expenses	$	21

· Higher plant generation costs are primarily attributable to a higher level of scheduled maintenance and overhaul work.

Demand Side Management (DSM) Program Expenses — DSM program expenses increased by approximately $17.6 million, or 35.4 percent, for the first six months of 2010, compared with the first six months of 2009. The higher expense is attributable to the ongoing expansion of such programs as designed, in part, to meet certain regulatory commitments in Colorado.

Depreciation and Amortization — Depreciation and amortization increased by approximately $10.7 million, or 8.5 percent, for the first six months of 2010, compared with the first six months of 2009. The increase is primarily due to planned system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $4.9 million, or 10.7 percent, for the first six months of 2010, compared with the first six months of 2009. The increase is primarily due to an increase in property taxes.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased by approximately $19.8 million for the first six months of 2010, compared with the first six months of 2009. The decrease was partially due to recovery of Comanche Unit 3 financing costs through base rates and lower AFUDC rates.

Interest Charges — Interest charges increased by approximately $5.3 million, or 6.5 percent, for the first six months of 2010, compared with the first six months of 2009, primarily due to increased long-term borrowings.

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Income Taxes — Income tax expense increased by $50.3 million for the first six months of 2010, compared with the first six months of 2009. The increase in income tax expense was primarily due to an increase in pretax income, a write-off of tax benefits previously recorded for Medicare Part D subsidies, and an adjustment at PSRI related to the COLI Tax Court proceedings. For further information, see Note 4 to the consolidated financial statements. The effective tax rate was 42.5 percent for the first six months of 2010, compared with 33.3 percent for the same period in 2009. The higher effective tax rate for the first six months of 2010 was primarily due to a higher forecasted annual effective tax rate and the write-off of tax benefit for Medicare Part D subsidies and the adjustment at PSRI in 2010. Without these two charges, the effective tax rate for the first six months of 2010 would have been 36.2 percent. The higher forecasted annual effective tax rate for 2010 as compared to 2009 was primarily due to reduced plant-related deductions and the elimination of tax benefits for Medicare Part D subsidies in 2010, partially offset by increased state unitary tax benefit in 2010.

Factors Affecting Results of Continuing Operations

Public Utility Regulation

PSCo Resource Plan — In October 2009, the CPUC approved the acquisitions of the resources identified in the bid evaluation report filed with the CPUC in August 2009. With minor modification, the CPUC adopted PSCo’s preferred plan, which includes an incremental 900 MW of additional intermittent renewable energy resources (wind and photovoltaic (PV) solar) and approximately 280 MW of “new technology” renewable energy sources. The CPUC approved the negotiation of purchased power contracts from a pool of PV solar bidders, rather than designating specific bidders. The CPUC approved the selection of about 900 MW of traditional gas-fired resources. The CPUC preferred that PSCo file its next resource plan in the normal course of business in the fall of 2011 rather than making an interim filing in 2010. The Colorado OCC has appealed the CPUC’s approval of the resource plan to Denver District Court, arguing that the CPUC erred in approving a portfolio where PSCo obtained an ownership interest in gas-fired generation and that this portfolio will not result in just and reasonable rates.

In May 2010, PSCo filed for approval to purchase approximately 900 MW of gas-fired generation from subsidiaries of Calpine Corporation consistent with the CPUC approved portfolio. PSCo has the ability to terminate the transaction if conditions on regulatory approval are unacceptable. The purchase is subject to federal and state regulatory approvals including approval of the proposed recovery of costs. In June 2010, the Federal Trade Commission provided notice of the early termination of the waiting period for premerger review. In July 2010, the FERC issued an order approving the acquisition. The parties must obtain approval of the Federal Communications Commission for transfer of radio licenses associated with the plants, which is the remaining federal regulatory approval. The application includes prompt recovery of revenue requirements associated with the transaction. The matter has been referred to an ALJ and the ALJ has set a schedule to resolve the matter by the target closing date of Dec. 1, 2010. Intervenor testimony is due Aug. 9, 2010.

In June 2010, PSCo filed an amendment to the approved resource plan to reduce the amount of solar resources (combination of PV solar and new technology renewable energy resources) acquired to an amount that could be accommodated using existing transmission facilities. This change was necessitated by delays in the certificate of public convenience and necessity process to develop a significant new transmission project that would allow access to the Colorado’s best solar resource. The request to reduce solar acquisitions up to 185 MW will ensure that PSCo will not be subject to significant curtailment payments due to use of non-firm transmission. The matter is pending before the CPUC.

San Luis Valley-Calumet-Comanche Unit 3 Transmission Project — PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a certificate of need and public convenience in May 2009. The project consists of four components of both 230 KV and 345 KV line and substation construction. The line is intended to assist in bringing solar power in the San Luis Valley to load. As noted in the aforementioned PSCo Resource Plan, the line was originally expected to be placed in-service in 2013; however, that appears unlikely now due to delays in the siting and permitting of the line. Several landowners are opposing this transmission line, including two large ranches. Hearings before an ALJ were conducted in February 2010, and additional hearings were held on July 26 and 30, 2010.

RES — In March 2010, Colorado enacted a law that increases the RES to 30 percent of energy sales to be supplied by renewable energy for PSCo and removes the solar standard and replaces it with a distributed generation standard. Within the distributed generation standard, at least one-half of the distributed generation must be retail distributed generation, i.e., generation that is on customer premises behind the customer meter. The law requires that PSCo generate or cause to be generated electricity from renewable resources equaling:

· At least 12 percent of its retail sales for the years 2011 through 2014;

· At least 20 percent of its retail sales for the years 2015 through 2019; and

· At least 30 percent of its retail sales for the years 2020 and thereafter.

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In addition, distributed generation must equal:

· At least 1 percent of retail sales in the years 2011 and 2012 and 1.25 percent of retail sales in the years 2013 and 2014;

· At least 1.75 percent of retail sales in the years 2015 and 2016 and 2 percent of retail sales in the years 2017, 2018 and 2019; and

· At least 3 percent of retail sales in the years 2020 and thereafter.

The CPUC has discretion to review the reasonableness of the increase in the distributed generation percentage in 2014. The CPUC commenced a rulemaking in April 2010 to incorporate changes from the 2010 RES into CPUC rules. PSCo believes that its forecasted plan acquisitions of renewable resources only need minor modification to comply with the new standard.

In June 2010, Colorado enacted “Solar Garden” legislation that allows PSCo customers to purchase shares of a larger solar facility instead of putting solar panels on their rooftops. In June 2010, the CPUC indicated that it would initiate a separate rulemaking to accommodate this new law. The rulemaking is expected to commence prior to October 2010. In PSCo’s 2011 RES compliance plan, PSCo is expected to include its initial Solar Garden product offering.

Colorado Clean Air-Clean Jobs Act — The Colorado Clean Air-Clean Jobs Act (the Act) was signed into law in April 2010. The Act requires PSCo to file a comprehensive plan with the CPUC by Aug. 15, 2010 to reduce annual emissions of NOx by at least 70 to 80 percent from 2008 levels from the coal-fired generation identified in the plan. The plan must consider emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by Jan. 1, 2018. The legislation requires PSCo to prepare comparative evaluations of different scenarios, including a scenario where emission controls are installed on the coal plants and a scenario where coal plants are repowered or replaced by natural gas by Jan. 1, 2015. The legislation further encourages PSCo to submit long-term gas contracts to the CPUC for approval. If approved, PSCo would be entitled to recover the costs it incurs under these long-term gas contracts, notwithstanding any change in the market price of natural gas during the term of the contract.

Pursuant to the Act, PSCo is entitled to fully recover the costs that it prudently incurs in executing an approved emission reduction plan and is allowed a return on CWIP on plan investments. In addition, if early action is taken to retire or convert units to natural gas, and PSCo shows that the costs of the plan would contribute to any earnings deficiency, additional relief, including a more comprehensive rider to recover other plant costs such as depreciation and O&M expense, or a multi-year rate plan are allowed. The Act permits the CPUC to consider interim rate increases after Jan. 1, 2012 while the rate filing is pending.

In June, CPUC ordered PSCo to file certain information so that it could process the August filing in a timely manner. PSCo has filed a significant amount of information with the CPUC and in July 2010 provided a list of the different scenarios it has proposed to model for its plan filing. Also in July 2010, the CPUC rejected a motion by Colorado Independent Energy Association, representing certain independent power producers that would require PSCo to consider purchasing replacement capacity under the plan from these entities. See additional information set forth in Note 6 to the consolidated financial statements in this Quarterly Report on Form 10-Q.

SmartGridCity™ Certificate of Public Convenience and Necessity (CPCN) — As part of the recent PSCo electric rate case, the CPUC included recovery of the revenue requirements associated with the capital and O&M costs incurred by PSCo to develop and operate SmartGridCity™ subject to refund and ordered PSCo to file for a CPCN for that project. PSCo filed that application on March 10, 2010 along with direct testimony. Answer testimony was received from parties on July 19, 2010. The CPUC staff, the OCC, and the Governor’s Energy Office (GEO) support the issuance of the CPCN and cost recovery of the amounts included in the rate case. Two parties, Leslie Glustrom and Arapahope Community Team (ACT) oppose issuance of the CPCN. PSCo is currently recovering the revenue requirements on $42 million of capital costs and $4 million in annual O&M costs. The OCC and Glustrom recommended partial recovery of capital costs while ACT recommended no recovery. PSCo’s rebuttal testimony is due in early August 2010. Separately, PSCo has received approval to conduct both a pricing and an in-home device pilot program to evaluate the customer response to price signals enabled by the smart technology.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices, and certain other activities of Xcel Energy’s utility subsidiaries, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s utility activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2009. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

Table of Contents

Part II — OTHER INFORMATION

Item 1 — Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against PSCo. After consultation with legal counsel, PSCo has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Additional Information

See Notes 5 and 6 of the financial statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Notes 14 and 15 of PSCo’s consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2009 for a description of certain legal proceedings presently pending.

Item 1A — Risk Factors

Except to the extent updated or described below, PSCo’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2009, which is incorporated herein by reference.

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHG, and federal legislation has been introduced in both houses of Congress. Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA. On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. The EPA finalized GHG efficiency standards for light duty vehicles in spring 2010 and has promulgated permitting requirements for GHGs for large new and modified stationary sources, such as power plants. These regulations will become applicable in 2011. We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 6, Commitments and Contingent Liabilities, in the notes to the consolidated financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Many of the federal and state climate change legislative proposals, such as the American Clean Energy and Security Act and the proposed Kerry-Lieberman legislation, use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation will be enacted. The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

PART I - FINANCIAL INFORMATION

Item l.	Financial Statements (Unaudited)	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 4.	Controls and Procedures	31

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 6.	Exhibits	33

SIGNATURES		34

Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

2.01* †		Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as Sellers, and PSCo, as Purchaser, dated as of April 2, 2010 (excluding certain schedules and exhibits referred to in the agreement, as amended, which the Registrant agrees to furnish supplementally to the SEC upon request). (Exhibit 2.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2010).
3.01*		Amended and Restated Articles of Incorporation dated July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*		By-laws dated Nov. 20, 1997 (For 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
10.01*		Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2010).
10.02*		Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2010).
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.

	Public Service Company of Colorado
	(Registrant)

August 2, 2010	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Vice President and Controller

	/s/ DAVID M. SPARBY
	David M. Sparby
	Vice President and Chief Financial Officer

	/s/ DAVID L. EVES
	David L. Eves
	President and Chief Executive Officer

	/s/ DAVID M. SPARBY
	David M. Sparby
	Vice President and Chief Financial Officer