Public Service Co Of Colorado 10-Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2011

or

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. T 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). T 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 T	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 T 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 Aug. 1, 2011
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.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 4 —	Controls and Procedures	30
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	30
Item 1A —	Risk Factors	31
Item 6 —	Exhibits	32
SIGNATURES		33
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Public Service Company of Colorado, a Colorado corporation (PSCo). PSCo is a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); PSCo; and Southwestern Public Service Company, a New Mexico corporation (SPS). Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

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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,
	2011			2010			2011			2010
Operating revenues
Electric	$	749,791		$	773,621		$	1,453,944		$	1,497,255
Natural gas		174,730			165,894			602,921			632,177
Steam and other		8,579			7,781			20,682			20,561
Total operating revenues		933,100			947,296			2,077,547			2,149,993
Operating expenses
Electric fuel and purchased power		352,216			408,113			676,013			781,964
Cost of natural gas sold and transported		94,022			82,121			398,960			422,830
Cost of sales — steam and other		3,989			2,931			9,110			9,004
Other operating and maintenance expenses		186,668			169,025			357,339			324,718
Demand side management program expenses		27,767			33,550			58,089			67,261
Depreciation and amortization		80,277			69,217			160,246			136,183
Taxes (other than income taxes)		34,985			25,662			69,306			50,278
Total operating expenses		779,924			790,619			1,729,063			1,792,238
Operating income		153,176			156,677			348,484			357,755
Other income, net		2,235			1,326			3,898			1,882
Allowance for funds used during construction — equity		1,798			3,279			3,417			6,257
Interest charges and financing costs
Interest charges — includes other financing costs of $1,760, $1,409, $3,276 and $2,806, respectively		46,036			41,626			91,435			87,439
Allowance for funds used during construction — debt		(820	)		(1,426	)		(1,546	)		(3,091	)
Total interest charges and financing costs		45,216			40,200			89,889			84,348
Income before income taxes		111,993			121,082			265,910			281,546
Income taxes		40,975			43,397			98,262			119,611
Net income	$	71,018		$	77,685		$	167,648		$	161,935

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,
	2011			2010
Operating activities
Net income	$	167,648		$	161,935
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		162,890			138,590
Demand side management program amortization		5,091			14,562
Deferred income taxes		89,067			42,245
Amortization of investment tax credits		(1,335	)		(1,168	)
Allowance for equity funds used during construction		(3,417	)		(6,257	)
Net realized and unrealized hedging and derivative transactions		19,310			(9,697	)
Changes in operating assets and liabilities:
Accounts receivable		35,878			46,213
Accrued unbilled revenues		73,003			98,842
Inventories		20,067			56,489
Prepayments and other		28,819			47,588
Accounts payable		(37,276	)		(137,259	)
Net regulatory assets and liabilities		(32,457	)		16,571
Other current liabilities		(15,066	)		(6,901	)
Pension and other employee benefit obligations		(58,054	)		(11,262	)
Change in other noncurrent assets		(162	)		(1,650	)
Change in other noncurrent liabilities		(11,442	)		(4,962	)
Net cash provided by operating activities		442,564			443,879
Investing activities
Utility capital/construction expenditures		(278,282	)		(222,564	)
Allowance for equity funds used during construction		3,417			6,257
Investments in utility money pool		(3,300	)		(347,200	)
Repayments from utility money pool		3,300			268,200
Net cash used in investing activities		(274,865	)		(295,307	)
Financing activities
Repayment of short-term borrowings, net		(120,400	)		(95,000	)
Borrowings under utility money pool arrangement		176,500			184,900
Repayments under utility money pool arrangement		(176,500	)		(268,900	)
Capital contributions from parent		76,221			137,791
Dividends paid to parent		(135,047	)		(132,477	)
Net cash used in financing activities		(179,226	)		(173,686	)
Net decrease in cash and cash equivalents		(11,527	)		(25,114	)
Cash and cash equivalents at beginning of period		32,912			33,429
Cash and cash equivalents at end of period	$	21,385		$	8,315
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(86,865	)	$	(78,547	)
Cash received (paid) for income taxes, net		35,043			(11,318	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	88,364		$	15,272

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, 2011		Dec. 31, 2010
Assets
Current assets
Cash and cash equivalents	$	21,385	$	32,912
Accounts receivable, net		270,055		305,469
Accounts receivable from affiliates		20,578		21,042
Accrued unbilled revenues		224,532		297,535
Inventories		202,991		223,058
Regulatory assets		172,321		176,596
Deferred income taxes		8,380		13,877
Derivative instruments		5,262		6,294
Prepayments and other		15,821		54,235
Total current assets		941,325		1,131,018
Property, plant and equipment, net		9,292,437		9,200,556
Other assets
Regulatory assets		826,656		824,205
Derivative instruments		15,110		18,035
Other		54,022		55,016
Total other assets		895,788		897,256
Total assets	$	11,129,550	$	11,228,830
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	5,770	$	6,970
Short-term debt		149,000		269,400
Accounts payable		338,859		382,380
Accounts payable to affiliates		26,520		28,270
Regulatory liabilities		57,369		50,018
Taxes accrued		74,440		94,321
Accrued interest		49,203		48,866
Dividends payable to parent		67,589		66,828
Derivative instruments		15,410		29,047
Other		103,968		100,984
Total current liabilities		888,128		1,077,084
Deferred credits and other liabilities
Deferred income taxes		1,624,802		1,539,583
Deferred investment tax credits		46,003		47,338
Regulatory liabilities		438,970		472,846
Asset retirement obligations		75,721		72,687
Derivative instruments		39,703		43,220
Customer advances		233,806		244,345
Pension and employee benefit obligations		245,854		303,946
Other		63,006		61,334
Total deferred credits and other liabilities		2,767,865		2,785,299
Commitments and contingent liabilities
Capitalization
Long-term debt		3,227,966		3,228,253
Common stock – authorized 100 shares of $0.01 par value; outstanding 100 shares		-		-
Additional paid in capital		3,331,807		3,255,586
Retained earnings		906,991		875,151
Accumulated other comprehensive income		6,793		7,457
Total common stockholder's equity		4,245,591		4,138,194
Total liabilities and equity	$	11,129,550	$	11,228,830

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of June 30, 2011 and Dec. 31, 2010; the results of its operations for the three and six months ended June 30, 2011 and 2010; and its cash flows for the six months ended June 30, 2011 and 2010. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2011 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2010 balance sheet information has been derived from the audited 2010 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2010. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2010, filed with the SEC on Feb. 28, 2011. Due to the seasonality of PSCo’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2010, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides additional guidance for fair value measurements. These updates to the FASB Accounting Standards Codification (ASC or Codification) include clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity and disclosures regarding the sensitivity of Level 3 measurements to changes in valuation model inputs. These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011. PSCo does not expect the implementation of this guidance to have a material impact on its consolidated financial statements.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which updates the Codification to require the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous statement of comprehensive income or in two separate, but consecutive statements of net income and comprehensive income. These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income. These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011. PSCo does not expect the implementation of this guidance to have a material impact on its consolidated financial statements.

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3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2011			Dec. 31, 2010
Accounts receivable, net
Accounts receivable	$	293,229		$	329,523
Less allowance for bad debts		(23,174	)		(24,054	)
	$	270,055		$	305,469
Inventories
Materials and supplies	$	52,439		$	51,615
Fuel		83,814			67,187
Natural gas		66,738			104,256
	$	202,991		$	223,058
Property, plant and equipment, net
Electric plant	$	9,186,932		$	9,003,103
Natural gas plant		2,329,053			2,284,212
Common and other property		772,351			757,059
Plant to be retired (a)		199,315			236,606
Construction work in progress		247,551			231,636
Total property, plant and equipment		12,735,202			12,512,616
Less accumulated depreciation		(3,442,765	)		(3,312,060	)
	$	9,292,437		$	9,200,556

(a) In 2009, in accordance with the Colorado Public Utilities Commission (CPUC’s) approval of PSCo’s 2007 Colorado resource plan and subsequent rate case decisions, PSCo agreed to early retire its Cameo Units 1 and 2, Arapahoe Units 3 and 4 and Zuni Units 1 and 2 facilities. In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the CPUC approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. Amounts are presented net of accumulated depreciation.

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2010 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expired in August 2010. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expires in September 2011. The Internal Revenue Service (IRS) commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of June 30, 2011, the IRS had not proposed any material adjustments to tax years 2008 and 2009.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2011, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006. As of June 30, 2011, there were no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (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, 2011		Dec. 31, 2010
Unrecognized tax benefit — Permanent tax positions	$	1.4	$	1.3
Unrecognized tax benefit — Temporary tax positions		10.0		10.3
Unrecognized tax benefit balance	$	11.4	$	11.6

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

(Millions of Dollars)	June 30, 2011			Dec. 31, 2010
NOL and tax credit carryforwards	$	(7.3	)	$	(7.2	)

PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefits could decrease up to approximately $8 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2011 and Dec. 31, 2010 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2011 or Dec. 31, 2010.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in the PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2010 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 — CPUC

Base Rate

PSCo 2010 Gas Rate Case — In December 2010, PSCo filed a request with the CPUC to increase Colorado retail gas rates by $27.5 million on an annual basis. In March 2011, PSCo revised its requested rate increase to $25.6 million. The revised request was based on a 2011 forecast test year, a 10.90 percent return on equity (ROE), a rate base of $1.1 billion and an equity ratio of 57.10 percent. PSCo proposed recovering $23.2 million of test year capital and operating and maintenance (O&M) expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006. PSCo also proposed removing the earnings on gas in underground storage from base rates.

In May 2011, PSCo filed a comprehensive settlement with CPUC Staff and the Colorado Office of Consumer Counsel (OCC) to increase rates by $10.9 million, to institute rider recovery of future integrity management costs, and to remove underground storage from base rates and recover those costs in the Gas Cost Adjustment (GCA) rider. The GCA recovery of the return on gas in storage is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs. Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent. New base rates and the GCA recovery is expected to go into effect in September 2011. The rider for integrity management costs is expected to go into effect on Jan. 1, 2012 and is expected to recover an estimated $13 million of incremental revenue in 2012. In July 2011, the CPUC approved the settlement with certain modifications and PSCo subsequently filed exceptions to the recommended decision.

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

PSCo Wholesale Rate Case — In February 2011, PSCo filed a request with the FERC to change Colorado wholesale electric customer rates to formula based rates with an expected increase of $16.1 million annually for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a wholesale rate base of $407.4 million and an equity ratio of 57.1 percent. Under the proposal, the formula rate would be estimated annually and then would be trued up to actual costs after the conclusion of the year. The primary drivers of the revenue deficiency are the recently acquired Blue Spruce Energy Center and Rocky Mountain Energy Center generating units, as well as the costs of early retirement of certain coal plants under the CACJA emissions reduction plan, all of which were approved by the presiding hearing commissioner in late 2010. In April 2011, the FERC suspended the effective date five months, allowing the rates to be placed into effect on Sept. 10, 2011, subject to refund and set the request for settlement procedures.

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Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing Settlement — In May 2010, the CPUC approved a settlement on the treatment of margins associated with sales of Colorado RECs that are bundled with energy into California. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides that margins would be shared based on the following allocations:

Margin	Customers			PSCo			Carbon Offsets
Less than $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. Margins associated with sales of unbundled stand-alone RECs without energy would be credited 100 percent to customers.

In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of REC trading margins that allows the customers’ share of the margins through the end of the pilot period, approximately $54 million, to be netted against the renewable energy standard adjustment (RESA) regulatory asset balance. At June 30, 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

In June 2011, PSCo filed an application for permanent treatment of Colorado RECs that are bundled with energy into California. The application is seeking margin sharing of 30 percent to PSCo and 70 percent to customers for deliveries outside of California and 40 percent to PSCo and 60 percent to customers for deliveries inside of California. PSCo also proposed that sales of RECs bundled with on-system energy be aggregated with other trading margins and shared 20 percent to PSCo and 80 percent to customers. The CPUC has indicated a desire to expedite the matter and a decision is expected in the fourth quarter of 2011.

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 12 and 13 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2010, 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— The accounting guidance for consolidation of variable interest entities 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 enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — Under certain purchased power agreements, PSCo purchases power from independent power producing entities that own natural gas fueled power plants for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases.

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 O&M costs, 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. PSCo had approximately 1,882 megawatts (MW) and 2,010 MW of capacity under long-term purchased power agreements as of June 30, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2028.

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Guarantees — In connection with the purchase agreement, PSCo provides for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.

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 — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regarding the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances to the environment. 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, 2011 and Dec. 31, 2010, the liability for the cost of remediating these sites was estimated to be $0.7 million and $0.8 million, respectively, of which $0.2 million and $0.3 million, respectively, was considered to be a current liability.

Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. 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 13 of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2010. 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 not expected to be material 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

Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Rulemaking — In December 2009, the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA plans to propose GHG regulations applicable to emissions from existing power plants under the Clean Air Act (CAA). In June 2011, the EPA announced that they have delayed the proposal date to September 2011, but still plan on issuing final rules in May 2012.

Electric Generating Unit (EGU) Maximum Achievable Control Technology (MACT) Rule — In 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulated mercury emissions from power plants. In February 2008, the United States (U.S.) Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules.

In March 2011, the EPA issued the proposed EGU MACT designed to address emissions of mercury and other hazardous air pollutants for coal-fired utility units greater than 25 MW. The EPA intends to issue the final rule by November 2011. PSCo anticipates that the EPA will require affected facilities to demonstrate compliance within three to four years.

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 the end of 2011. 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 has evaluated the Colorado mercury control requirements for its other units in Colorado and believes that, under the current regulations, no further controls will be required other than the planned controls at the Pawnee Generating Station. The Pawnee mercury controls are included in the CACJA plan.

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Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. PSCo generating facilities will be subject to BART requirements. Individual states are required to identify the facilities located in their states that will have to reduce sulfer dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.

In 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. In January 2011, the Colorado Air Quality Commission approved a revised Regional Haze BART/Reasonable Further Progress state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan. In accordance with Colorado law, the SIP passed the Colorado general assembly, was signed by the governor and was submitted to the EPA. PSCo anticipates that for those plants included in the Colorado CACJA emission reduction plan, the SIP will satisfy regional haze requirements. The Colorado SIP, however, must be approved by the EPA. PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2017.

In March 2010, two environmental groups petitioned the U.S. Department of the 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.

Federal Clean Water Act (CWA Section 316 (b)) — The federal 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 to aquatic species. In April 2011, the EPA published the proposed rule that was modified to address earlier court decisions. The proposed rule sets prescriptive standards for minimization of aquatic species impingement but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. PSCo is evaluating the proposed rule, including possible additional capital and operating expenses, and plans to offer comments to the EPA. Due to the uncertainty of the final regulatory requirements, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

Proposed Coal Ash Regulation — PSCo’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste. 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 hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, PSCo’s costs associated with the management and disposal of coal ash would significantly increase, and the beneficial reuse of coal ash would be negatively impacted. The EPA has not announced a planned date for a final rule. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

Notice of Violation (NOV) — In 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 also 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. 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.

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Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — 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 the following utilities, including Xcel Energy Inc., the parent company of PSCo, to force reductions in carbon dioxide (CO2) emissions: American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) 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. In September 2005, the court granted plaintiffs’ motion to dismiss on constitutional grounds. In August 2010, this decision was reversed by the Second Circuit and was appealed to the U.S. Supreme Court. On June 20, 2011, the Supreme Court issued a ruling reversing the Second Circuit’s decision, thereby dismissing plaintiffs’ federal claims and remanding the case for further proceedings regarding the state law claims.

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 Inc., the parent company of PSCo, and 23 other utility, 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 Inc. and PSCo believe the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 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. The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina. Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million. No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — On May 27, 2011, less than one year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi. The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property. Plaintiffs base their claims on public and private nuisance, trespass and negligence. Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota. The amount of damages claimed by plaintiffs is unknown. It is believed that this lawsuit is without merit. No accrual has been recorded for this matter.

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. 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. Oral arguments were presented in December 2010. In June 2011, the Colorado Supreme Court affirmed the decision of the Court of Appeals.

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 (CCH) 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 the federal Occupational Safety and Health Administration (OSHA), the U.S. Chemical Safety Board (CSB) and the Colorado Bureau of Investigations.

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. Pursuant to a court order this proceeding had been stayed until July 1, 2011. The stay has now been lifted, and the matter is expected to proceed.

Three lawsuits were filed (two in Colorado state court and one in California state court) on behalf of the five deceased workers and by seven employees of RPI allegedly injured in the accident. PSCo and Xcel Energy Inc. were among the defendants named in each lawsuit. Settlements were subsequently reached in all three lawsuits by Xcel Energy Inc. and PSCo. These confidential settlements did not have a material adverse effect upon Xcel Energy’s consolidated results of operations, cash flows or financial position.

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In August 2009, the U.S. Government charged Xcel Energy Inc. and PSCo 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 were also indicted. In September 2009, both Xcel Energy Inc. and PSCo entered a not-guilty plea. On June 28, 2011, a jury returned a not-guilty verdict on all accounts in favor of Xcel Energy Inc. and PSCo.

In August 2010, the CSB issued a report related to its investigation of the CCH accident. The report contains several findings and recommendations, some of which pertain to PSCo. Consistent with its delegated authority, the CSB investigation did not result in the issuance of any fines or penalties. PSCo has responded to the CSB concerning its recommendations.

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. The complaint also alleges that Xcel Energy Inc. 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. In total, Shaw seeks approximately $144 million in damages.

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 total, PSCo is seeking approximately $82 million in damages. 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. In September 2010, Shaw filed a second lawsuit related to PSCo’s decision to draw on the letter of credit. PSCo denied the merits of this claim.

Trial commenced in October 2010 and addressed only those issues raised in the first complaint and did not include Shaw’s claim asserted in the second lawsuit related to the letter of credit. In November 2010, a jury returned a verdict that awarded damages to Shaw and to PSCo. Specifically, the jury awarded a total of $84.5 million to Shaw but also awarded $70.0 million to PSCo for damages related to its counterclaims, for a net verdict to Shaw in the amount of $14.5 million. Shaw subsequently filed post trial motions, which the court denied. In March 2011, Shaw filed its notice of appeal on all issues raised at trial and in post-trial motions. PSCo filed a conditional cross-appeal on April 5, 2011. If the jury verdict remains unchanged it is not expected to have a material adverse effect on Xcel Energy’s consolidated results of operations, cash flows or financial position.

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, Colo. 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. In September 2010, six plaintiffs filed a fourth lawsuit, Vigil vs. Xcel Energy Inc., in Hennepin County District Court in Minneapolis, Minn., alleging personal injury and property damage as a result of the November 2008 explosion. In January 2011, the court granted Xcel Energy Inc.’s motion to dismiss this lawsuit on procedural grounds. The damages claimed by plaintiffs in the three Colorado lawsuits are presently unknown but it is not believed that this total, if recovered, would have a material adverse effect upon PSCo’s consolidated results of operations, cash flows or financial position. No trial date has been set for these lawsuits.

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7. Borrowings and Other Financing Instruments

Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. The following table presents commercial paper outstanding for PSCo:

(Millions of Dollars)	Three Months Ended June 30, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	700		$	675
Amount outstanding at period end		149			269
Average amount outstanding		79			49
Maximum amount outstanding		150			275
Weighted average interest rate, computed on a daily basis		0.35	%		0.37	%
Weighted average interest rate at end of period		0.35			0.42

Credit Facilities — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under the credit agreement.

During March of 2011, PSCo executed a new 4-year credit agreement. The total size of the credit facility is $700 million and terminates in March 2015. PSCo has the right to request an extension of the revolving termination date for two additional one year periods, subject to majority bank group approval.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Other features of PSCo’s credit facility include:

· The credit facility may be increased by up to $100 million.

· The credit facility has a financial covenant requiring that PSCo’s debt-to-total capitalization ratio be less than or equal to 65 percent. PSCo was in compliance as its debt-to-total capitalization ratio was 44 percent and 46 percent at June 30, 2011 and Dec. 31, 2010, respectively. If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

· The credit facility has a cross-default provision that provides PSCo will be in default on its borrowings under the facility if Xcel Energy Inc. or any of its subsidiaries, comprising 15 percent or more of the consolidated assets, defaults on any indebtedness in an aggregate principal amount exceeding $75 million.

· The interest rates under the line of credit are based on the Eurodollar rate, plus a borrowing margin based on the applicable credit ratings of 100 to 200 basis points per year.

· The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the line of credit at a range of 10 to 35 basis points per year.

At June 30, 2011, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility		Drawn (a)		Available
$	700.0	$	153.6	$	546.4

(a) Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at June 30, 2011 and Dec. 31, 2010.

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, 2011 and Dec. 31, 2010, there were $4.6 million and $4.7 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.

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. 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 Xcel Energy Inc.

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The following table presents the money pool borrowings for PSCo:

(Millions of Dollars)	Three Months Ended June 30, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	250		$	250
Amount outstanding at period end		-			-
Average amount outstanding		5			8
Maximum amount outstanding		36			84
Weighted average interest rate, computed on a daily basis		0.33	%		0.33	%
Weighted average interest rate at end of period		N/A			N/A

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain 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 reporting 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 reporting 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 reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Commodity derivatives— 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 delivery 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.

Derivative Instruments 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.

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 an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At June 30, 2011, accumulated 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.

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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 products. PSCo’s risk management policy allows management to conduct these 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.

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, 2011, PSCo had vehicle fuel contracts designated as cash flow hedges extending through December 2014. 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 three and six months ended June 30, 2011 and 2010.

At June 30, 2011, accumulated OCI related to commodity derivative cash flow hedges included $0.1 million of net gains 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 electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards and options at June 30, 2011 and Dec. 31, 2010:

(Amounts in Thousands) (a) (b)	June 30, 2011		Dec. 31, 2010
Megawatt hours (MWh) of electricity		2,183		2,418
MMBtu of natural gas		40,622		59,465
Gallons of vehicle fuel		315		360

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

(b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

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 tables:

	Three Months Ended June 30,
(Thousands of Dollars)	2011			2010
Accumulated other comprehensive income related to cash flow hedges at April 1	$	7,198		$	7,993
After-tax net unrealized losses related to derivatives accounted for as hedges		(16	)		(123	)
After-tax net realized gains on derivative transactions reclassified into earnings		(389	)		(166	)
Accumulated other comprehensive income related to cash flow hedges at June 30	$	6,793		$	7,704

	Six Months Ended June 30,
(Thousands of Dollars)	2011			2010
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	7,457		$	8,101
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		82			(108	)
After-tax net realized gains on derivative transactions reclassified into earnings		(746	)		(289	)
Accumulated other comprehensive income related to cash flow hedges at June 30	$	6,793		$	7,704

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PSCo had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2011 and June 30, 2010. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2011 and June 30, 2010, respectively, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2011
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:
(Thousands of Dollars)	Other Comprehensive Loss			Regulatory Assets and Liabilities			Other Comprehensive Loss			Regulatory Assets and Liabilities			Pre-Tax Loss Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(582	) (a)	$	-		$	-
Vehicle fuel and other commodity		(43	)		-			(27	) (c)		-			-
Total	$	(43	)	$	-		$	(609	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	(150	) (b)
Natural gas commodity		-			(7,792	)		-			738	(d)		-
Total	$	-		$	(7,792	)	$	-		$	738		$	(150	)

	Six Months Ended June 30, 2011
	Fair Value Changes Recognized During the Period in:					Pre-Tax Amounts Reclassified into Income During the Period from:
(Thousands of Dollars)	Other Comprehensive Income		Regulatory Assets and Liabilities			Other Comprehensive Loss			Regulatory Assets and Liabilities			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-		$	(1,159	) (a)	$	-		$	-
Vehicle fuel and other commodity		133		-			(45	) (c)		-			-
Total	$	133	$	-		$	(1,204	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-	$	-		$	-		$	-		$	95	(b)
Natural gas commodity		-		(13,146	)		-			45,220	(d)		-
Total	$	-	$	(13,146	)	$	-		$	45,220		$	95

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	Three Months Ended June 30, 2010
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:
(Thousands of Dollars)	Other Comprehensive Loss			Regulatory Assets and Liabilities			Other Comprehensive Income (Loss)			Regulatory Assets and Liabilities			Pre-Tax Gains (Loss) 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:
(Thousands of Dollars)	Other Comprehensive Loss			Regulatory Assets and Liabilities			Other Comprehensive Income (Loss)			Regulatory Assets and Liabilities			Pre-Tax Gains  (Loss) 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	)

(a) Recorded to interest charges.

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

(c) Recorded to O&M expenses.

(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 $5.1 million and $5.6 million of derivative instruments in a liability position at June 30, 2011 and Dec. 31, 2010, respectively, would have required PSCo to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $5.7 million and $9.8 million, respectively. At June 30, 2011 and Dec. 31, 2010, 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, 2011 and Dec. 31, 2010.

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, 2011:

	June 30, 2011
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	91	$	-	$	91	$	(91	)	$	-
Other derivative instruments:
Trading commodity		-		5,046		-		5,046		(2,383	)		2,663
Natural gas commodity		-		209		-		209		(209	)		-
Total current derivative assets	$	-	$	5,346	$	-	$	5,346	$	(2,683	)		2,663
Purchased power agreements (a)													2,599
Current derivative instruments												$	5,262
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	129	$	-	$	129	$	-		$	129
Other derivative instruments:
Trading commodity		-		5,599		-		5,599		(1,798	)		3,801
Total noncurrent derivative assets	$	-	$	5,728	$	-	$	5,728	$	(1,798	)		3,930
Purchased power agreements (a)													11,180
Noncurrent derivative instruments												$	15,110
Current derivative liabilities
Other derivative instruments:
Trading commodity	$	46	$	4,702	$	-	$	4,748	$	(2,470	)	$	2,278
Natural gas commodity		-		7,732		-		7,732		(300	)		7,432
Total current derivative liabilities	$	46	$	12,434	$	-	$	12,480	$	(2,770	)		9,710
Purchased power agreements (a)													5,700
Current derivative instruments												$	15,410
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	4,658	$	-	$	4,658	$	(1,798	)	$	2,860
Total noncurrent derivative liabilities	$	-	$	4,658	$	-	$	4,658	$	(1,798	)		2,860
Purchased power agreements (a)													36,843
Noncurrent derivative instruments												$	39,703

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, 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) The accounting guidance for 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.

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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, 2011 and June 30, 2010.

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, 2010:

	Dec. 31, 2010
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	56	$	-	$	56	$	-		$	56
Other derivative instruments:
Trading commodity		-		5,765		-		5,765		(2,633	)		3,132
Natural gas commodity		-		1,396		-		1,396		(1,019	)		377
Total current derivative assets	$	-	$	7,217	$	-	$	7,217	$	(3,652	)		3,565
Purchased power agreements (a)													2,729
Current derivative instruments												$	6,294
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	68	$	-	$	68	$	-		$	68
Other derivative instruments:
Trading commodity		-		6,770		-		6,770		(2,118	)		4,652
Natural gas commodity		-		1,111		-		1,111		(211	)		900
Total noncurrent derivative assets	$	-	$	7,949	$	-	$	7,949	$	(2,329	)		5,620
Purchased power agreements (a)													12,415
Noncurrent derivative instruments												$	18,035
Current derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	5,192	$	-	$	5,192	$	(2,669	)	$	2,523
Natural gas commodity		-		41,753		-		41,753		(20,969	)		20,784
Total current derivative liabilities	$	-	$	46,945	$	-	$	46,945	$	(23,638	)		23,307
Purchased power agreements (a)													5,740
Current derivative instruments												$	29,047
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	5,526	$	-	$	5,526	$	(2,118	)	$	3,408
Natural gas commodity		-		350		-		350		(211	)		139
Total noncurrent derivative liabilities	$	-	$	5,876	$	-	$	5,876	$	(2,329	)		3,547
Purchased power agreements (a)													39,673
Noncurrent derivative instruments												$	43,220

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, 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) The accounting guidance for 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.

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The following table presents the changes in Level 3 recurring fair value measurements for the three and six months ended June 30, 2010. There were no changes in Level 3 recurring fair value measurements for the three and six months ended June 30, 2011.

(Thousands of Dollars)	Three Months Ended June 30, 2010			Six Months Ended June 30, 2010
Balance at beginning of period	$	331		$	804
Purchases		(80	)		(135	)
Settlements		(33	)		(128	)
Gains recognized in earnings (a)		381			58
Balance at June 30	$	599		$	599

(a) These amounts relate to commodity derivatives held at the end of the period.

Fair Value of Long-Term Debt

The historical cost and fair value of PSCo’s long-term debt are as follows:

	June 30, 2011				Dec. 31, 2010
(Thousands of Dollars)	Historical Cost		Fair Value		Historical Cost		Fair Value
Long-term debt, including current portion	$	3,233,736	$	3,519,675	$	3,235,223	$	3,531,729

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. The fair value estimates presented are based on information available to management as of June 30, 2011 and Dec. 31, 2010. 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.

As of June 30, 2011 and Dec. 31, 2010, the historical cost of cash and cash equivalents, notes and accounts receivable, notes and accounts payable and short-term debt are representative of fair value because of the short-term nature of these instruments.

9. Other Income, Net

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

	Three Months Ended June 30,					Six Months Ended June 30,
(Thousands of Dollars)	2011			2010		2011			2010
Interest income	$	1,390		$	741	$	2,693		$	1,119
Other nonoperating income		742			428		1,353			859
Insurance policy income (expense)		106			157		(141	)		(96	)
Other nonoperating expense		(3	)		-		(7	)		-
Other income, net	$	2,235		$	1,326	$	3,898		$	1,882

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10. Segment Information

PSCo has the following reportable segments: regulated electric, regulated natural gas and all other.

· PSCo’s regulated electric utility segment generates, transmits and distributes electricity in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the U.S. Regulated electric utility also includes PSCo’s commodity trading operations.

· PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado.

· Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities.

Operating results from the regulated electric utility and regulated natural gas utility serve as the primary basis for the chief operating decision maker to evaluate the dual performance of PSCo. The accounting policies of the segments are the same as those described in Note 1 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2010. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery which is separately determined for each segment.

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

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2011
Operating revenues from external customers	$	749,791	$	174,730	$	8,579		$	-		$	933,100
Intersegment revenues		70		173		-			(243	)		-
Total revenues	$	749,861	$	174,903	$	8,579		$	(243	)	$	933,100
Net income	$	66,801	$	2,661	$	1,556		$	-		$	71,018
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
Six Months Ended June 30, 2011
Operating revenues from external customers	$	1,453,944	$	602,921	$	20,682		$	-		$	2,077,547
Intersegment revenues		184		219		-			(403	)		-
Total revenues	$	1,454,128	$	603,140	$	20,682		$	(403	)	$	2,077,547
Net income	$	132,516	$	31,539	$	3,593		$	-		$	167,648
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

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11. Comprehensive Income

The components of total comprehensive income are shown below:

	Three Months Ended June 30,
(Thousands of Dollars)	2011			2010
Net income	$	71,018		$	77,685
Other comprehensive loss:
After-tax net unrealized losses related to derivatives accounted for as hedges		(16	)		(123	)
After-tax net realized gains on derivative transactions reclassified into earnings		(389	)		(166	)
Other comprehensive loss		(405	)		(289	)
Comprehensive income	$	70,613		$	77,396

	Six Months Ended June 30,
(Thousands of Dollars)	2011			2010
Net income	$	167,648		$	161,935
Other comprehensive income (loss):
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		82			(108	)
After-tax net realized gains on derivative transactions reclassified into earnings		(746	)		(289	)
Other comprehensive loss		(664	)		(397	)
Comprehensive income	$	166,984		$	161,538

12. 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,
	2011			2010			2011			2010
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy
Service cost	$	20,548		$	18,956		$	1,097		$	965
Interest cost		40,791			41,853			10,492			10,861
Expected return on plan assets		(55,514	)		(58,035	)		(8,013	)		(7,131	)
Amortization of transition obligation		-			-			3,611			3,611
Amortization of prior service cost (credit)		5,633			5,164			(1,233	)		(1,233	)
Amortization of net loss		20,527			13,134			3,304			3,113
Net periodic pension cost		31,985			21,072			9,258			10,186
Costs not recognized and additional cost recognized due to the effects of regulation		(10,715	)		(6,314	)		973			973
Net benefit cost recognized for financial reporting	$	21,270		$	14,758		$	10,231		$	11,159
PSCo
Net periodic benefit cost	$	7,971		$	4,329		$	4,974		$	5,640
Additional cost recognized due to the effects of regulation		-			-			973			973
Net benefit cost recognized for financial reporting	$	7,971		$	4,329		$	5,947		$	6,613

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	Six Months Ended June 30,
	2011			2010			2011			2010
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy
Service cost	$	38,660		$	36,574		$	2,412		$	2,003
Interest cost		80,706			82,505			21,043			21,390
Expected return on plan assets		(110,800	)		(116,159	)		(15,981	)		(14,265	)
Amortization of transition obligation		-			-			7,222			7,222
Amortization of prior service cost (credit)		11,266			10,328			(2,466	)		(2,466	)
Amortization of net loss		39,256			24,158			6,647			5,822
Net periodic pension cost		59,088			37,406			18,877			19,706
Costs not recognized and additional cost recognized due to the effects of regulation		(18,600	)		(13,640	)		1,946			1,946
Net benefit cost recognized for financial reporting	$	40,488		$	23,766		$	20,823		$	21,652
PSCo
Net periodic benefit cost	$	15,181		$	7,652		$	10,544		$	11,153
Additional cost recognized due to the effects of regulation		-			-			1,946			1,946
Net benefit cost recognized for financial reporting	$	15,181		$	7,652		$	12,490		$	13,099

Voluntary contributions of $134 million were made to three of Xcel Energy’s pension plans in January 2011, including $58.3 million related to PSCo.Based on updated valuation results received in March 2011 for the NCE Non-Bargaining Pension Plan, Xcel Energy made a required contribution of $3.3 million to the NCE Non-Bargaining Pension Plan in July 2011.

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

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

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on PSCo’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements. Due to the seasonality of PSCo’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2010, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2011.

Results of Operations

PSCo’s net income was approximately $167.6 million for the six months ended June 30, 2011, compared with approximately $161.9 million for the same period in 2010. Higher 2011 net income reflects lower income tax expense partially offset by a decrease in revenues due to seasonal rates, which were implemented in June 2010, and higher O&M expenses, property taxes and depreciation expense. Seasonal rates are designed to be revenue neutral on an annual basis. Therefore, the quarterly pattern of revenue collection is different than in the past, as seasonal rates are higher in the summer months and lower throughout the latter part of the year. Income tax expense in 2010 was higher due to a write-off of tax benefits previously recorded for Medicare Part D subsidies and an adjustment at P.S.R. Investments, Inc. (PSRI) related to the corporate-owned life insurance (COLI) Tax Court proceedings in 2010.

Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas and coal used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin:

	Six Months Ended June 30,
(Millions of Dollars)	2011			2010
Electric revenues	$	1,454			$	1,497
Electric fuel and purchased power		(676	)			(782	)
Electric margin	$	778			$	715

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

Electric Revenues

(Millions of Dollars)	2011 vs. 2010
Fuel and purchased power cost recovery	$	(109	)
Retail rate increase, offset by impact of seasonal rates		(8	)
Firm wholesale		(6	)
Conservation and DSM revenue (offset by expenses)		(5	)
Revenue requirements for PSCo generation acquisition (a)		69
Renewable energy credit sales		7
Non-fuel riders		5
Conservation and DSM incentive		2
Transmission revenue		2
Total decrease in electric revenues	$	(43	)

Electric Margin

(Millions of Dollars)	2011 vs. 2010
Revenue requirements for PSCo generation acquisition (a)	$	69
Non-fuel riders		5
Conservation and DSM incentive		2
Retail rate increase, offset by impact of seasonal rates		(8	)
Firm wholesale		(6	)
Conservation and DSM revenue (offset by expenses)		(5	)
Other		6
Total increase in electric margin	$	63

(a) The increase in revenue requirements for PSCo generation reflects the acquisition of the Rocky Mountain and Blue Spruce natural gas facilities in 2010. These revenue requirements are partially offset by increased O&M expense, depreciation expense, property taxes and financing costs.

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details the natural gas revenues and margin:

	Six Months Ended June 30,
(Millions of Dollars)	2011			2010
Natural gas revenues	$	603			$	632
Cost of natural gas sold and transported		(399	)			(423	)
Natural gas margin	$	204			$	209

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

Natural Gas Revenues

(Millions of Dollars)	2011 vs. 2010
Purchased natural gas adjustment clause recovery	$	(24	)
Retail sales decrease (excluding weather impact)		(5	)
Total decrease in natural gas revenues	$	(29	)

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Natural Gas Margin

(Millions of Dollars)	2011 vs. 2010
Retail sales decrease (excluding weather impact)	$	(5	)
Total decrease in natural gas margin	$	(5	)

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased by approximately $32.6 million, or 10.0 percent, for the six months ended June 30, 2011, compared with the same period in 2010. The following summarizes the changes in other O&M expenses:

(Millions of Dollars)	2011 vs. 2010
Higher plant generation costs	$	16
Higher labor/contract labor costs		8
Higher employee benefit costs		5
Higher lease costs		3
Higher consulting costs		2
Other		(1	)
Total increase in operating and maintenance expenses	$	33

Higher plant generation costs are primarily attributable incremental operating costs associated with new generation facilities placed in service in 2010.

Demand Side Management (DSM) Program Expenses —DSM program expenses decreased by approximately $9.2 million, or 13.6 percent, for the six months ended June 30, 2011, compared with the same period in 2010. The lower expense was primarily attributable to the timing of and a reduction in historical amortization of DSM programs. PSCo has established DSM incentive programs designed to encourage its retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas and/or electric system. This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers. PSCo recovers DSM program expenses concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization increased by approximately $24.1 million, or 17.7 percent, for the six months ended June 30, 2011, compared with the same period in 2010. The increase is primarily due to Comanche Unit 3 going into service in the second quarter of 2010, the acquisition of two gas generation facilities in December 2010 and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $19.0 million, or 37.8 percent, for the six months ended June 30, 2011, compared with the same period in 2010. 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 $4.4 million for the six months ended June 30, 2011, compared with the same period in 2010. The decrease was primarily due to lower AFUDC rates, primarily driven by lower interest rates.

Interest Charges —Interest charges increased by approximately $4.0 million, or 4.6 percent, for the six months ended June 30, 2011, compared with the same period in 2010, primarily due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense decreased by $21.3 million for the second quarter of 2011, compared with the same period in 2010. The higher income tax expense in 2010 was primarily due to 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 in 2010. The effective tax rate was 37.0 percent for the second quarter of 2011, compared with 42.5 percent for the same period in 2010. The higher effective tax rate for the six months ended June 30, 2010 was primarily due to 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.

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Factors Affecting Results of Operations

Public Utility Regulation

Solar*Rewards Program — In February 2011, PSCo filed to reduce the payments to customers installing on-site solar generation due to changes in market conditions resulting from the decrease in cost of solar energy. In March 2011, PSCo entered into a settlement agreement with CPUC Staff, OCC, Colorado Solar Energy Industries Association, Solar Alliance, Western Resource Advocates, Colorado Governor’s Energy Office and Colorado Renewable Energy Society that limits the amount of customer sited solar generation that PSCo will purchase, caps the amount PSCo will spend on customer sited solar, and quickly shifts from up-front payments to pay-for-performance. The settlement gives PSCo a presumption of prudence, for both the existing RESA balance, and the future RESA balance if PSCo performs consistent with the acquisition terms of the settlement. The CPUC approved the settlement and the program was reopened on March 23, 2011. Separately, the CPUC approved a change to the treatment of REC trading margins that allows the customers’ share of the margins through the end of the pilot period, approximately $54 million, to be netted against the RESA regulatory asset balance. At June 30, 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

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

In December 2010, the CPUC approved the following:

· Shutdown Cherokee Units 1 and 2 in 2011 and Cherokee Unit 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);

· Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017;

· Shutdown Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (111 MW) in 2014 to natural gas;

· Shutdown Valmont Unit 5 (186 MW) in 2017;

· Install selective catalytic reduction (SCR) for controlling NOx and a scrubber for controlling SO2 on Pawnee Station in 2014;

· Install SCR on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and

· Convert Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.

The CPUC provided for recovery on construction work in process in rate base in each rate case and deferred accounting of accelerated depreciation costs. PSCo needs to make applications for detailed cost review before commencing each phase of the plan. The CPUC also encouraged PSCo to hold stakeholder meetings to discuss issues around a multi-year rate plan. In January 2011, the Colorado Air Quality Control Commission unanimously approved incorporation of the CACJA plan into Colorado’s regional haze SIP. See Note 3 and Note 5 to the consolidated financial statements for discussion. In April 2011, the Colorado General Assembly approved legislation authorizing the regional haze SIP containing the CACJA plan. Upon signature by the Governor of Colorado, the SIP (including the CACJA plan) was sent to the EPA for incorporation into federal CAA regulations. The total investment associated with the adopted plan is approximately $1.0 billion over the next seven years. The rate impact of the proposed plan is expected to increase future bills on average by 2 percent annually.

In March 2011, PSCo filed an application for approval of the conversion of Cherokee Unit 2 to a synchronous condenser and notified the CPUC that it could maintain transmission system reliability potentially without conversion of Arapahoe Unit 3. PSCo and parties submitted an unopposed motion to approve the Certificate of Public Convenience and Necessity (CPCN) for Cherokee Unit 2 and defer the decision on Arapahoe Unit 3 until after a full reliability study is completed by the end of 2012. The Administrative Law Judge (ALJ) is expected to issue a decision regarding the settlement by the end of the third quarter 2011.

In April 2011, PSCo filed for approval of the decommissioning of Cherokee 1 and 2 to provide space for the new combined-cycle plant. Although answer testimony was due July 8, 2011, none was filed. In addition, PSCo filed for approval of the emissions controls on Pawnee Station. Hearing dates for this matter have been scheduled for Oct. 17-19, 2011.

Cameo Generating Station — In 2008, the CPUC approved PSCo’s request to retire the 73 MW Cameo coal-fired generating station at the end of 2011. Cameo Station was retired at the end of 2010. In February 2011, PSCo filed a plan for decommissioning, remediation, removal, and restoration at the site. The plan was approved without hearing and work is expected to begin during the summer of 2011.

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San Luis Valley-Calumet-Comanche Unit 3 Transmission Project — In May 2009, PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a project for 230 kilovolts (KV) and 345 KV line and substation construction. The line is intended to assist in bringing solar power in the San Luis Valley to customers. 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 oppose this transmission line, including two large ranches. In November 2010, the ALJ issued a recommended decision granting the CPCN but proposing a significant refund obligation if the line was not heavily utilized ten years after it was in service. Several parties, including PSCo, filed exceptions to the recommended decision. The CPUC deliberated on the exceptions to the recommended decision and granted the CPCN without the refund obligation recommended by the ALJ. A written decision was issued on March 23, 2011. The matter remains subject to an application for reconsideration by two parties.

SmartGridCity™ CPCN — As part of the PSCo 2010 electric rate case, the CPUC included recovery of the revenue requirements associated with $45 million of capital and $4 million of annual 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.

In February 2011, the CPUC approved the CPCN and allowed recovery of approximately $28 million of the capital cost and 100 percent of the O&M costs and ordered PSCo to file for a rate reduction in April 2011 to reflect the lower level of capital in rate base. The CPUC seeks additional information regarding the future plans to utilize SmartGridCity™ in an application to recover the additional capital. PSCo believes that it will be able to satisfy that requirement. On July 1, 2011, PSCo implemented an annual rate reduction of $2.8 million. PSCo plans to file the additional information in the fourth quarter of 2011.

Colorado DSM Strategic Issues Filing —The CPUC approved higher savings goals and a slightly higher financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2012. Savings goals will increase to 130 percent of the current goals and incentives will be awarded as one installment in the year following plan achievements. This is a revision to current CPUC policy of awarding incentives in two installments over a multi-year period. PSCo will also be able to earn an incentive on 11 percent of net economic benefits at an achievement level of 130 percent and a maximum annual incentive of $30 million.

Boulder, Colo. Franchise Agreement — The Boulder, Colo. City Council is exploring forming a municipal utility, instead of renewing their franchise agreement with PSCo. The franchise agreement expired in 2010; however, PSCo continues to provide service under its CPUC certificate. The Boulder City Council originally expressed an interest in providing its residents with electricity derived primarily from renewable energy. PSCo had developed a proposal that would provide a substantially higher amount of renewable energy to Boulder, which the parties could not agree upon. Should the voters approve the formation of a municipal utility and the condemnation of the PSCo distribution system, PSCo will work to ensure that customers in Colorado recover the appropriate level of stranded costs and the value of the distribution system. At Dec. 31, 2010, the City of Boulder represented approximately 3.7 percent of PSCo’s electric sales.

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 PSCo, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s 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, 2010. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

NERC Electric Reliability Standards Compliance

Compliance Audits and Self Reports

In November 2010, PSCo filed a self-report with the Western Electricity Coordinating Council regarding potential violations of certain NERC critical infrastructure protection standards (CIPS). Additional self-reports of potential violations of CIPS standards were filed in January 2011. Based on the issues identified with CIPS compliance, PSCo submitted a mitigation plan that provides for a comprehensive review of its CIPS compliance programs. Whether and to what extent penalties may be assessed against PSCo for the issues identified and self-reported to date is unclear.

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FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement, the DOI, commenced a non-public investigation of the transmission service arrangements across the Lamar Tie Line, a transmission facility that connects PSCo and SPS. In July 2008, the DOI issued a preliminary report alleging Xcel Energy violated certain FERC policies, rules and approved tariffs, that could result in material penalties under the FERC penalty guidelines. The report does not constitute a finding by the FERC, which may accept, modify or reject any or all of the preliminary conclusions set forth in the report. Xcel Energy disagreed with the preliminary report and demonstrated compliance with applicable standards. In December 2010, the DOI initiated settlement discussions with Xcel Energy regarding possible resolution of the non-public investigation and settlement discussions are continuing. The final outcome of the DOI investigation and to what extent the FERC may seek to impose penalties for alleged violations is unknown at this time. The potential violations are not expected to have a material impact on PSCo’s financial condition, results of operations or cash flows.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of June 30, 2011, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting.

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 consolidated financial statements 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 12 and 13 of PSCo’s consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2010 for a description of certain legal proceedings presently pending.

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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, 2010, which is incorporated herein by reference.

Public Policy Risks

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

Increased public awareness and concern regarding climate change 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 GHGs, and federal legislation has been introduced in both houses of Congress. Internationally, other nations have already agreed to regulate emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” by 2012. In addition, in 2009, the U.S. submitted a non-binding GHG emission reduction target of 17 percent compared to 2005 levels pursuant to the Copenhagen Accord. Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as 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. In December 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 created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants in September 2011, with final standards to be issued in May 2012.

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. 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 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 or regulation 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 U.S., 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 be able to timely 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.

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include, but are not limited to, rules associated with mercury, regional haze, ozone, ash management and cooling water intake systems. The costs of investment to comply with these rules could be substantial. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

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Item 6 — Exhibits

* Indicates incorporation by reference

t Furnished, herewith, not filed. Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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)).

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.

101 t The following materials from PSCo’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Cash Flow, (iii) the Consolidated Balance Sheets, (iv) Notes to Condensed Consolidated Financial Statements, and (v) document and entity information.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Public Service Company of Colorado
Aug. 1, 2011
	By:	/s/ TERESA S. MADDEN
		Teresa S. Madden
		Vice President and Controller
		/s/ DAVID M. SPARBY
		David M. Sparby
		Vice President and Chief Financial Officer

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