PUBLIC SERVICE CO OF COLORADO - FORM 10-Q

Attached files

file	filename
EX-99.01 - EXHIBIT 99.01 - PUBLIC SERVICE CO OF COLORADO	ex99_01.htm
EX-31.01 - EXHIBIT 31.01 - PUBLIC SERVICE CO OF COLORADO	ex31_01.htm
EX-32.01 - EXHIBIT 32.01 - PUBLIC SERVICE CO OF COLORADO	ex32_01.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended Sept. 30, 2010

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). o Yes o No

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

Large accelerated filer o	Accelerated filer o

Non-accelerated filer 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 Oct. 29, 2010
Common Stock, $0.01 par value		100 shares

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

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	25
Item 4.	Controls and Procedures	32

PART II - OTHER INFORMATION

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

SIGNATURES		34

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). Additional information on 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 Sept. 30,						Nine Months Ended Sept. 30,
	2010			2009			2010			2009
Operating revenues
Electric	$	849,707		$	771,663		$	2,346,962		$	1,957,473
Natural gas		101,203			109,398			733,380			678,013
Steam and other		4,060			6,899			24,621			24,045
Total operating revenues		954,970			887,960			3,104,963			2,659,531

Operating expenses
Electric fuel and purchased power		379,871			397,904			1,161,835			1,005,972
Cost of natural gas sold and transported		31,267			40,821			454,097			415,623
Cost of sales — steam and other		3,396			3,171			12,400			9,721
Other operating and maintenance expenses		165,985			158,557			490,703			462,047
Demand side management program expenses		32,228			27,560			99,489			77,226
Depreciation and amortization		72,540			64,436			208,723			189,897
Taxes (other than income taxes)		26,628			25,679			76,906			71,079
Total operating expenses		711,915			718,128			2,504,153			2,231,565

Operating income		243,055			169,832			600,810			427,966

Other income, net		25,949			427			27,831			3,408
Allowance for funds used during construction — equity		2,544			10,396			8,801			30,220

Interest charges and financing costs
Interest charges — includes other financing costs of $1,392, $1,440, $4,198 and $4,259, respectively		40,686			42,645			128,125			124,779
Allowance for funds used during construction — debt		(1,111	)		(4,487	)		(4,202	)		(13,816	)
Total interest charges and financing costs		39,575			38,158			123,923			110,963

Income before income taxes		231,973			142,497			513,519			350,631
Income taxes		73,882			51,273			193,493			120,573
Net income	$	158,091		$	91,224		$	320,026		$	230,058

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)

	Nine Months Ended Sept. 30,
	2010			2009
Operating activities
Net income	$	320,026		$	230,058
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		212,353			193,521
Demand side management program expenses		17,120			20,344
Deferred income taxes		94,588			166,836
Amortization of investment tax credits		(1,752	)		(1,872	)
Allowance for equity funds used during construction		(8,801	)		(30,220	)
Net realized and unrealized hedging and derivative transactions		(47,982	)		41,244
Changes in operating assets and liabilities:
Accounts receivable		73,274			117,429
Accrued unbilled revenues		109,790			168,854
Recoverable purchased natural gas and electric energy costs		7,617			(35,002	)
Inventories		(4,783	)		1,553
Prepayments and other		43,106			(31,659	)
Accounts payable		(154,001	)		(168,492	)
Deferred electric energy costs		(12,381	)		(86,390	)
Net regulatory assets and liabilities		49,115			22,670
Other current liabilities		10,068			(9,415	)
Change in other noncurrent assets		(2,676	)		5,169
Change in other noncurrent liabilities		(27,361	)		(114,349	)
Net cash provided by operating activities		677,320			490,279

Investing activities
Utility capital/construction expenditures		(382,902	)		(439,509	)
Allowance for equity funds used during construction		8,801			30,220
Investments in utility money pool		(697,500	)		(205,200	)
Repayments from utility money pool		636,500			178,200
Net cash used in investing activities		(435,101	)		(436,289	)

Financing activities
Repayment of short-term borrowings, net		(95,000	)		(40,000	)
Proceeds from issuance of long-term debt		-			394,594
Repayment of long-term debt, including reacquisition premiums		-			(200,000	)
Borrowings under utility money pool arrangement		184,900			574,800
Repayments under utility money pool arrangement		(268,900	)		(615,800	)
Capital contributions from parent		137,791			40,417
Dividends paid to parent		(199,206	)		(200,193	)
Net cash used in financing activities		(240,415	)		(46,182	)

Net increase in cash and cash equivalents		1,804			7,808
Cash and cash equivalents at beginning of period		33,429			11,198
Cash and cash equivalents at end of period	$	35,233		$	19,006

Supplemental disclosure of cash flow information:
Cash paid for interest, net of amounts capitalized	$	(117,053	)	$	(109,394	)
Cash (paid) received for income taxes, net		(46,150	)		35,306
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	16,752		$	12,450
Storage assets under capital lease		-			134,150

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)

	Sept. 30, 2010		Dec. 31, 2009
Assets
Current assets
Cash and cash equivalents	$	35,233	$	33,429
Accounts receivable, net		281,948		330,279
Accounts receivable from affiliates		13,242		33,396
Investments in utility money pool arrangement		61,000		-
Accrued unbilled revenues		204,163		313,953
Recoverable purchased natural gas and electric energy costs		17,540		25,157
Inventories		258,431		253,648
Deferred income taxes		68,128		81,980
Derivative instruments valuation		16,866		28,704
Prepayments and other		24,502		58,968
Total current assets		981,053		1,159,514

Property, plant and equipment, net		8,298,575		8,104,841

Other assets
Regulatory assets		883,983		827,311
Derivative instruments valuation		81,890		104,664
Other		52,654		47,175
Total other assets		1,018,527		979,150
Total assets	$	10,298,155	$	10,243,505

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	6,394	$	3,964
Short-term debt		-		95,000
Borrowings under utility money pool arrangement		-		84,000
Accounts payable		286,244		422,276
Accounts payable to affiliates		26,209		40,758
Deferred electric energy costs		52,171		64,552
Taxes accrued		84,159		80,303
Dividends payable to parent		66,601		65,822
Derivative instruments valuation		37,068		18,285
Accrued interest		48,206		47,300
Other		100,904		67,692
Total current liabilities		707,956		989,952

Deferred credits and other liabilities
Deferred income taxes		1,532,918		1,447,143
Deferred investment tax credits		48,279		50,031
Regulatory liabilities		512,291		510,491
Pension and employee benefit obligations		242,331		257,881
Customer advances		249,325		271,171
Derivative instruments valuation		46,899		49,587
Asset retirement obligations		68,309		65,160
Other		58,283		31,287
Total deferred credits and other liabilities		2,758,635		2,682,751

Commitments and contingent liabilities
Capitalization
Long-term debt		2,828,427		2,824,988
Common stock – authorized 100 shares of $0.01 par value; outstanding 100 shares		-		-
Additional paid-in capital		3,133,261		2,995,470
Retained earnings		862,285		742,243
Accumulated other comprehensive income		7,591		8,101
Total common stockholder's equity		4,003,137		3,745,814
Total liabilities and equity	$	10,298,155	$	10,243,505

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 Sept. 30, 2010 and Dec. 31, 2009; the results of its operations for the three and nine months ended Sept. 30, 2010 and 2009; and its cash flows for the nine months ended Sept. 30, 2010 and 2009. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2010 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, 2009 balance sheet information has been derived from the audited 2009 consolidated financial statements. 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, 2009, filed with the SEC on March 1, 2010. 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

Except to the extent updated or described below, the significant accounting policies set forth in Note 1 to the consolidated financial statements in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2009, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Reclassifications — Demand side management program expenses for the nine months ended Sept. 30, 2009 were reclassified as a separate line item from depreciation and amortization expenses within the consolidated statements of cash flows. The reclassification did not have an impact on net cash provided by operating activities.

2.	Accounting Pronouncements

Recently Adopted

Consolidation of Variable Interest Entities — In June 2009, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the FASB Accounting Standards Codification (ASC or Codification) were effective for interim and annual periods beginning after Nov. 15, 2009. PSCo implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements. For further information and required disclosures regarding variable interest entities, see Note 6 to the consolidated financial statements.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (Accounting Standards Update (ASU) No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. PSCo implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements. For further information and required disclosures, see Note 8 to the consolidated financial statements.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2010			Dec. 31, 2009
Accounts receivable, net
Accounts receivable	$	305,552		$	354,428
Less allowance for bad debts		(23,604	)		(24,149	)
	$	281,948		$	330,279
Inventories
Materials and supplies	$	49,490		$	45,809
Fuel		93,889			96,964
Natural gas		115,052			110,875
	$	258,431		$	253,648
Property, plant and equipment, net
Electric plant	$	8,619,286		$	7,635,325
Natural gas plant		2,204,406			2,133,116
Common and other property		739,942			731,511
Construction work in progress		310,029			1,038,013
Total property, plant and equipment		11,873,663			11,537,965
Less accumulated depreciation		(3,575,088	)		(3,433,124	)
	$	8,298,575		$	8,104,841

4.	Income Taxes

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

As part of the Tax Court proceedings, during the first quarter of 2010, Xcel Energy and the Internal Revenue Service (IRS) reached an agreement in principle after a comprehensive financial reconciliation of Xcel Energy’s statement of account, dating back to tax year 1993. Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $10 million (including $7.7 million tax expense and $2.3 million interest expense, net of tax), during the first quarter of 2010. During the third quarter of 2010, Xcel Energy and the IRS came to final agreement on the applicable interest netting computations related to these tax years. Accordingly, PSRI recorded a reduction to expense of $0.6 million, net of tax, during the third quarter of 2010. Xcel Energy anticipates that the Tax Court proceedings will be dismissed in the fourth quarter of 2010.

In July 2010, Xcel Energy, PSCo and PSRI entered into a settlement agreement with Provident Life & Accident Insurance Company (Provident) related to all claims asserted by Xcel Energy, PSCo and PSRI against Provident in a lawsuit associated with the discontinued COLI program. Under the terms of the settlement, Xcel Energy, PSCo and PSRI were paid $25 million by Provident and Reassure America Life Insurance Company in the third quarter of 2010. The $25 million proceeds are not subject to income taxes.

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

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

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Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. During the first quarter of 2010, the IRS completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expired in August 2010. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return will expire in September 2011. The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of Sept. 30, 2010, 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 Sept. 30, 2010, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

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

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

(Millions of Dollars)	Sept. 30, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	1.0	$	1.0
Unrecognized tax benefit - Temporary tax positions		8.9		6.2
Unrecognized tax benefit balance	$	9.9	$	7.2

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 were as follows:

(Millions of Dollars)		Sept. 30, 2010				Dec. 31, 2009
Tax benefits associated with NOL and tax credit carryforwards		$	(8.0	)		$	(4.0	)

The increase in the unrecognized tax benefit balance of $2.4 million from June 30, 2010 to Sept. 30, 2010 was due to the addition of uncertain tax positions related to current and prior years’ activity. The increase in the unrecognized tax benefit balance of $2.7 million from Dec. 31, 2009 to Sept. 30, 2010 was due to the addition of uncertain tax positions related to current and prior years’ activity, partially offset by a decrease due to recently provided guidance pertaining to plant-related uncertain tax positions. PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

5.	Rate Matters

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

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

Base Rate

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

·	A rate increase of $67 million was implemented on Jan. 1, 2010 because of the delay of the in-service date of Comanche Unit 3;

·	Base rates were increased to recover $123 million annually, on May 14, 2010 when Comanche Unit 3 went into service, including an additional $2 million of recovery for long-term debt interest in the working capital calculation granted under reconsideration; and

·	Base rates will increase to recover approximately $130 million annually on Jan. 1, 2011 to reflect 2011 property taxes.

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A second phase of the rate case addressed changes to rate design. The new rates approved by the CPUC went into effect on June 1, 2010. In this phase of the proceeding, the CPUC approved tiered summer rates for residential customers and seasonally differentiated rates for other customer classes, which will impact the timing of revenue collection, as compared to the previous rate design, depending on customer response. Seasonal rates are designed to be revenue neutral on an annual basis. However, the quarterly pattern of revenue collection will is expected to be different than in the past as seasonal rates are higher in the summer months and lower throughout the remainder of the year.

Electric, Purchased Gas and Resource Adjustment Clauses

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

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

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

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

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

Wholesale Rate Case — In 2009, PSCo filed a request with the FERC to increase electric rates to its firm wholesale customers by $30.7 million based on a 12.5 percent return on equity, a 58 percent equity ratio and a rate base of $315 million. During the summer of 2010, PSCo filed blackbox settlements with all of its wholesale customers. The settlements provided for new rates reflecting an electric rate increase of approximately $21.0 million for these customers effective in July 2010. In addition, on Jan. 1, 2011, an additional step rate increase of $1.0 million will be implemented for property taxes associated with Comanche Unit 3. The terms of the settlements provide for lower depreciation expense than requested and for certain capacity costs to be recovered through the fuel clause until those contracts expire. The FERC approved the settlements on Oct. 21, 2010.

6.	Commitments and Contingent Liabilities

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

Commitments

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

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

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

PSCo purchases power from independent power producing entities that own natural gas fueled power plants. Under certain purchased power agreements with these entities, 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 PSCo purchases. These purchased power agreements have been determined by PSCo to create variable interests in the independent power producing entities; therefore, certain independent power producing entities are variable interest entities.

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

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

Environmental Contingencies

PSCo has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense.

Site Remediation — PSCo must pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former manufactured gas plants operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent hazardous materials and wastes. At Sept. 30, 2010 and Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $0.8 million and $0.9 million, respectively, of which $0.3 million, was considered to be a current liability.

Third Party and Other Environmental Site Remediation

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

Other Environmental Requirements

Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Rulemaking — In December 2009, in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere. The EPA has promulgated permit requirements for GHGs for large new and modified stationary sources, such as power plants. These regulations will become applicable in 2011.

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Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize Maximum Achievable Control Technology (MACT) emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace the CAMR. PSCo anticipates that the EPA will require affected facilities to demonstrate compliance within three to five 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 2012 and other specified units by 2014. The expected cost estimate for the Pawnee Generating Station is $2.3 million for capital costs with an annual estimate of $1.4 million for sorbent expense. PSCo has evaluated the Colorado mercury control requirements for its other units in Colorado and believes that, under current regulations, no further controls will be required other than the planned controls at the Pawnee Generating Station.

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

In May 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. The Colorado Air Pollution Control Division (CAPCD) is currently analyzing what types of nitrogen oxide (NOx) controls may be necessary to meet BART and reasonable progress goals for Colorado’s Class I areas. The CAPCD has indicated that it expects to submit a Regional Haze BART/Reasonable Further Progress state implementation plan (SIP) to the EPA in early 2011. PSCo anticipates that for those plants included in the Clean Air-Clean Jobs Act’s (CACJA) emission reduction plan, the plan will satisfy regional haze requirements. 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 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 Clean Air Act (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 — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA challenging the phase II rulemaking. In April 2009, the U.S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA. The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules. Until the EPA fully responds, the rule’s compliance requirements and associated deadlines will remain unknown. As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

Proposed Coal Ash Regulation — In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as a special waste (subject to many of the requirements for hazardous waste) or as a solid (nonhazardous) waste. Coal ash is currently exempt from hazardous waste regulation. The EPA’s proposal would result in more comprehensive and expensive requirements related to management and disposal of coal ash. The EPA has extended the public comment period on the proposed rule until Nov. 19, 2010. The EPA is also seeking comment on what regulations are appropriate for the beneficial reuse of coal ash. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

PSCo Notice of Violation (NOV) — In July 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Station in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo 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.

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Legal Contingencies

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

Environmental Litigation

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 five utilities, including Xcel Energy, the parent company of PSCo, to force reductions in carbon dioxide (CO2) emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds. On appeal in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the lower court decision. In August 2010, defendants filed a petition for review with the U.S. Supreme Court.

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of PSCo, received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. Plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court. A subsequent petition by defendants, including Xcel Energy, for en banc review was granted. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit ruled that it lacked an en banc quorum of nine active members to hear the case. It dismissed the appeal, which resulted in the reinstatement of the district court’s opinion dismissing the case. Plaintiffs subsequently filed with the U.S. Supreme Court a writ of mandamus, which is a procedure requesting the court to order the Fifth Circuit to review plaintiffs’ earlier appeal. Defendants intend to oppose this request.

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

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

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

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Employment, Tort and Commercial Litigation

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

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

In July 2010, Plaintiffs entered into a settlement agreement with Provident and Reassure America Life Insurance Company. Under the terms of the settlement, Provident paid Plaintiffs $25 million. Xcel Energy recorded this settlement of $25 million in the third quarter of 2010. The $25 million proceeds are not subject to income taxes.

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 several state and federal agencies, including the federal Occupational Safety and Health Administration (OSHA) and 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. On May 28, 2008, the Secretary of Labor filed its complaint, and Xcel Energy subsequently filed its answer on June 17, 2008. The Court ordered this proceeding stayed until March 3, 2009 and has subsequently extended the stay until the criminal proceedings have concluded.

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

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

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 intends to respond to the CSB concerning its recommendations in due course.

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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 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 denies the merits of this claim.

Trial commenced on Oct. 18, 2010 and is expected to last approximately four weeks. The trial will address only those issues raised in the first complaint and will not include Shaw’s claim asserted in the second lawsuit related to the letter of credit.

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

7.	Short-Term Borrowings and Other Financing Instruments

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

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

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

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

(Millions of Dollars)	Sept. 30, 2010			Dec. 31, 2009
Money pool investments (borrowings)	$	61		$	(84	)
Weighted average interest rate		0.35	%		0.36	%
Money pool borrowing limit	$	250		$	250

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8.	Derivative Instruments and Fair Value Measurements

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

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. PSCo’s risk management policy allows management to conduct 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.

Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

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

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

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

At Sept. 30, 2010, accumulated OCI related to commodity derivative cash flow hedges included $0.3 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

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

(Amounts in Thousands) (a)	Sept. 30, 2010		Dec. 31, 2009
Megawatt hours (MWh) of electricity		6,068		3,559
MMBtu of natural gas		75,372		45,352
Gallons of vehicle fuel		525		1,559

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

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

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Accumulated other comprehensive income related to cash flow hedges at July 1	$	7,704		$	8,021
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		13			(75	)
After-tax net realized gains on derivative transactions reclassified into earnings		(126	)		(15	)
Accumulated other comprehensive income related to cash flow hedges at Sept. 30	$	7,591		$	7,931

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	Nine Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	8,101		$	7,628
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges		(95	)		131
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(415	)		172
Accumulated other comprehensive income related to cash flow hedges at Sept. 30	$	7,591		$	7,931

PSCo had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2010 and Sept. 30, 2009. 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 nine months ended Sept. 30, 2010 and Sept. 30, 2009, respectively, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 2010
	Fair Value Changes Recognized During the Period in:					Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Income (Losses)		Regulatory Assets and Liabilities			Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-		$	(589	)(a)	$	-		$	-
Vehicle fuel and other commodity		20		-			386	(c)		-			-
Total	$	20	$	-		$	(203	)	$	-		$	-

Other derivative instruments
Trading commodity	$	-	$	-		$	-		$	-		$	(568	)(b)
Natural gas commodity		-		(51,538	)		-			925	(d)		-
Total	$	-	$	(51,538	)	$	-		$	925		$	(568	)

	Nine Months Ended Sept. 30, 2010
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities			Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(1,747	)(a)	$	-		$	-
Vehicle fuel and other commodity		(154	)		-			1,078	(c)		-			-
Total	$	(154	)	$	-		$	(669	)	$	-		$	-

Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	(1,090	)(b)
Natural gas commodity		-			(82,824	)		-			5,314	(d)		-
Other		-			-			-			-			134	(b)
Total	$	-		$	(82,824	)	$	-		$	5,314		$	(956	)

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	Three Months Ended Sept. 30, 2009
	Fair Value Changes Recognized During the Period in:					Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities		Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-	$	(588	)(a)	$	-		$	-
Natural gas commodity		-			1,457		-			202	(d)		-
Vehicle fuel and other commodity		(122	)		-		574	(c)		-			-
Total	$	(122	)	$	1,457	$	(14	)	$	202		$	-

Other derivative instruments
Trading commodity	$	-		$	-	$	-		$	-		$	(350	)(b)
Natural gas commodity		-			39,815		-			1,325			-
Total	$	-		$	39,815	$	-		$	1,325		$	(350	)

	Nine Months Ended Sept. 30, 2009
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities			Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities
Derivatives designated as cash flow hedges
Interest rate	$	(632	)	$	-		$	(1,773	)(a)	$	-		$	-
Natural gas commodity		-			(14,641	)		-			66,311	(d)		(22,243	)(d)
Vehicle fuel and other commodity		843			-			2,060	(c)		-			-
Total	$	211		$	(14,641	)	$	287		$	66,311		$	(22,243	)

Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	2,193	(b)
Natural gas commodity		-			31,613			-			1,341	(d)		-
Total	$	-		$	31,613		$	-		$	1,341		$	2,193

(a)	Recorded to interest charges

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

(c)	Recorded to other 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 $7.7 million and $0.6 million of derivative instruments in a net liability position at Sept. 30, 2010 and Dec. 31, 2009, respectively, would have required PSCo to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $7.7 million and $3.4 million, respectively. At Sept. 30, 2010 and Dec. 31, 2009, there was no collateral posted on these specific contracts.

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 Sept. 30, 2010 and Dec. 31, 2009.

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Fair Value Measurements

ASC 820 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 reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

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

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

Recurring Fair Value Measurements

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

	Sept. 30, 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	$	-	$	26	$	-	$	26	$	(26	)	$	-
Other derivative instruments:
Trading commodity		3,669		14,698		-		18,367		(15,244	)		3,123
Natural gas commodity		-		24		-		24		(24	)		-
Total current derivative assets	$	3,669	$	14,748	$	-	$	18,417	$	(15,294	)		3,123
Purchased power agreements (a)													13,743
Current derivative instruments valuation												$	16,866
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	46	$	-	$	46	$	-		$	46
Other derivative instruments:
Trading commodity		-		9,565		-		9,565		(3,283	)		6,282
Natural gas commodity		-		10		-		10		-			10
Total noncurrent derivative assets	$	-	$	9,621	$	-	$	9,621	$	(3,283	)		6,338
Purchased power agreements (a)													75,552
Noncurrent derivative instruments valuation												$	81,890

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	Sept. 30, 2010
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	340	$	-	$	340	$	(26	)	$	314
Other derivative instruments:
Trading commodity		3,013		14,982		-		17,995		(17,447	)		548
Natural gas commodity		-		73,789		-		73,789		(43,323	)		30,466
Total current derivative liabilities	$	3,013	$	89,111	$	-	$	92,124	$	(60,796	)		31,328
Purchased power agreements (a)													5,740
Current derivative instruments valuation												$	37,068
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	8,156	$	-	$	8,156	$	(3,283	)	$	4,873
Natural gas commodity		-		918		-		918		-			918
Total noncurrent derivative liabilities	$	-	$	9,074	$	-	$	9,074	$	(3,283	)		5,791
Purchased power agreements (a)													41,108
Noncurrent derivative instruments valuation												$	46,899

(a)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, PSCo began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

(b)

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

PSCo recognizes transfers between levels as of the beginning of each period. The following table presents the transfers that occurred between levels during the three and nine months ended Sept. 30, 2010.

	From Level 3 to Level 2 (a) (b)
	Three Months Ended			Nine Months Ended
(Thousands of Dollars)	Sept. 30, 2010			Sept. 30, 2010
Trading commodity derivatives not designated as cash flow hedges:
Current assets	$	148		$	1,888
Noncurrent assets		-			4,988
Current liabilities		-			(1,265	)
Noncurrent liabilities		(833	)		(3,724	)
Total	$	(685	)	$	1,887

(a)	The transfer of amounts from Level 3 to Level 2 is due to the valuation of certain long term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.

(b)	There were no transfers of amounts from Level 2 to Level 3.

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

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

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

(a)

(b)

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

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

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

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Balance at July 1	$	599		$	2,673
Purchases and settlements, net		(308	)		(1,291	)
Transfers into Level 3		685			481
Losses recognized in earnings		(976	)		(1,030	)
Gains recognized as regulatory assets and liabilities		-			856
Balance at Sept. 30	$	-		$	1,689

	Nine Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Balance at Jan. 1	$	804		$	(26	)
Purchases and settlements, net		(570	)		(2,463	)
Transfers (out of) into Level 3		(1,887	)		1,069
Gains recognized in earnings		1,653			1,725
Gains recognized as regulatory assets and liabilities		-			1,384
Balance at Sept. 30	$	-		$	1,689

Losses on Level 3 commodity derivatives recognized in earnings for the three months ended Sept. 30, 2010, include $1.0 million of net unrealized losses relating to commodity derivatives held at Sept. 30, 2010. Losses on Level 3 commodity derivatives recognized in earnings for the three months ended Sept. 30, 2009, include $1.0 million of net unrealized losses relating to commodity derivatives held at Sept. 30, 2009. Gains on Level 3 commodity derivatives recognized in earnings for the nine months ended Sept. 30, 2010 and Sept. 30, 2009 included $1.5 million and $1.7 million, of net unrealized gains relating to commodity derivatives held at Sept. 30, 2010 and Sept. 30, 2009, respectively. Realized and unrealized gains and losses on commodity trading activities are included in electric revenues. Realized and unrealized gains and losses on short-term wholesale activities reflect the impact of regulatory recovery and are deferred as regulatory assets and liabilities.

9.	Financial Instruments

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

	Sept. 30, 2010				Dec. 31, 2009
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Other investments	$	8	$	8	$	8	$	8
Long-term debt, including current portion		2,834,821		3,246,727		2,828,952		3,050,249

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

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

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

10.	Other Income, Net

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

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009			2010			2009
Interest income	$	1,008		$	1,034		$	2,127		$	2,101
COLI settlement (See Note 4)		25,000			-			25,000			-
Other nonoperating income		383			297			1,242			2,751
Insurance policy expense		(442	)		(585	)		(538	)		(1,048	)
Other nonoperating expense		-			(319	)		-			(396	)
Other income, net	$	25,949		$	427		$	27,831		$	3,408

11.	Segment Information

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

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 Sept. 30, 2010
Operating revenues from external customers	$	849,707	$	101,203	$	4,060	$	-		$	954,970
Intersegment revenues		25		3		-		(28	)		-
Total revenues	$	849,732	$	101,206	$	4,060	$	(28	)	$	954,970
Net income	$	125,978	$	664	$	31,449	$	-		$	158,091

Three Months Ended Sept. 30, 2009
Operating revenues from external customers	$	771,663	$	109,398	$	6,899	$	-		$	887,960
Intersegment revenues		36		5		-		(41	)		-
Total revenues	$	771,699	$	109,403	$	6,899	$	(41	)	$	887,960
Net income	$	86,421	$	3,113	$	1,690	$	-		$	91,224

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2010
Operating revenues from external customers	$	2,346,962	$	733,380	$	24,621	$	-		$	3,104,963
Intersegment revenues		157		107		-		(264	)		-
Total revenues	$	2,347,119	$	733,487	$	24,621	$	(264	)	$	3,104,963
Net income	$	248,701	$	45,877	$	25,448	$	-		$	320,026

Nine Months Ended Sept. 30, 2009
Operating revenues from external customers	$	1,957,473	$	678,013	$	24,045	$	-		$	2,659,531
Intersegment revenues		182		52		-		(234	)		-
Total revenues	$	1,957,655	$	678,065	$	24,045	$	(234	)	$	2,659,531
Net income	$	173,480	$	45,968	$	10,610	$	-		$	230,058

12.	Comprehensive Income

The components of total comprehensive income are shown below:

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Net income	$	158,091		$	91,224
Other comprehensive (loss) income:
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		13			(75	)
After-tax net realized gains on derivative transactions reclassified into earnings		(126	)		(15	)
Other comprehensive loss		(113	)		(90	)
Comprehensive income	$	157,978		$	91,134

	Nine Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Net income	$	320,026		$	230,058
Other comprehensive (loss) income:
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges		(95	)		131
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(415	)		172
Other comprehensive (loss) income		(510	)		303
Comprehensive income	$	319,516		$	230,361

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13.	Benefit Plans and Other Postretirement Benefits

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

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30,
	2010			2009			2010			2009
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	18,286		$	16,365		$	1,002		$	1,166
Interest cost		41,253			42,448			10,695			12,603
Expected return on plan assets		(58,080	)		(64,135	)		(7,132	)		(5,694	)
Amortization of transition obligation		-			-			3,611			3,611
Amortization of prior service cost (credit)		5,165			6,155			(1,233	)		(681	)
Amortization of net loss		12,078			3,114			2,910			4,832
Net periodic benefit cost		18,702			3,947			9,853			15,837
Costs not recognized and additional cost recognized due to the effects of regulation		(6,630	)		(723	)		972			972
Net benefit cost recognized for financial reporting	$	12,072		$	3,224		$	10,825		$	16,809

PSCo:
Net periodic benefit cost	$	3,825		$	3,462		$	5,577		$	10,069
Additional cost recognized due to the effects of regulation		-			-			972			972
Net benefit cost recognized for financial reporting	$	3,825		$	3,462		$	6,549		$	11,041

	Nine Months Ended Sept. 30,
	2010			2009			2010			2009
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	54,860		$	49,095		$	3,005		$	3,499
Interest cost		123,758			127,343			32,085			37,809
Expected return on plan assets		(174,239	)		(192,404	)		(21,397	)		(17,082	)
Amortization of transition obligation		-			-			10,833			10,833
Amortization of prior service cost (credit)		15,493			18,464			(3,699	)		(2,044	)
Amortization of net loss		36,236			9,342			8,732			14,497
Net periodic benefit cost		56,108			11,840			29,559			47,512
Costs not recognized and additional cost recognized due to the effects of regulation		(20,270	)		(2,169	)		2,918			2,918
Net benefit cost recognized for financial reporting	$	35,838		$	9,671		$	32,477		$	50,430

PSCo:
Net periodic benefit cost	$	11,477		$	10,385		$	16,730		$	30,208
Additional cost recognized due to the effects of regulation		-			-			2,918			2,918
Net benefit cost recognized for financial reporting	$	11,477		$	10,385		$	19,648		$	33,126

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14.	PSCo Agreement to Acquire Assets from Calpine

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

The Rocky Mountain Energy Center is a 652 MW combined-cycle natural gas-fired power plant that began commercial operations in 2004. The Blue Spruce Energy Center is a 310 MW simple cycle natural gas-fired power plant that began commercial operations in 2003. Both power plants currently provide energy and capacity to PSCo under power purchase agreements, which were set to expire in 2013 and 2014.

The acquisition is subject to federal and state regulatory approvals including approval of the proposed recovery of costs. In June 2010, the Federal Trade Commission provided notice of the early termination of the waiting period under Hart-Scott-Rodino. In July 2010, the FERC issued an order approving the acquisition.

In September 2010, PSCo reached a partial settlement with the CPUC staff, the Colorado Independent Energy Association and the OCC, which provided for recovery of the revenue requirement (capital and O&M costs) associated with the transaction through an interim rider mechanism less a $3.9 million annual revenue reduction until PSCo implements new retail base rates. Additionally, in its next retail rate case, PSCo shall be allowed recovery of the net book value, based on the $739 million purchase price.

On Oct. 18, 2010, the CPUC approved the acquisition and the cost recovery settlement. The CPUC also required PSCo to file a rate case by April 30, 2012 to move the investment into rate base. The revenue requirements associated with the asset acquisition will continue to be recovered through the purchase capacity cost adjustment until final rates are implemented. Fuel costs will continue to flow through the energy cost adjustment and fuel cost adjustment mechanisms. The acquisition is expected to close in December 2010.

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.

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 the availability of credit and its impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; 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; environmental laws and regulations; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing 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, 2009, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2010.

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Market Risks

PSCo is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in its Annual Report on Form 10-K for the year ended Dec. 31, 2009. Commodity price and interest rate risks for PSCo are mitigated in most jurisdictions due to cost-based rate regulation.

Distress in the financial markets may impact the fair value of the debt and equity securities in pension and postretirement health care plan trusts, as well as PSCo’s ability to earn a return on short-term investments of excess cash. As of Sept. 30, 2010, there have been no material changes to market risks from that set forth in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2009.

Results of Operations

PSCo’s net income was approximately $320.0 million for the first nine months of 2010, compared with approximately $230.1 million for the first nine months of 2009. The increase is primarily due to rate increases, the timing of revenue collection as a result of the implementation of seasonal rates in June 2010 and warmer temperatures, which increased electric sales. The increase was partially offset by higher O&M expenses and depreciation expense. Seasonal rates are designed to be revenue neutral on an annual basis. As a result, the quarterly pattern of revenue collection is expected to be different than in the past as seasonal rates are higher in the summer months and lower throughout the remainder of the year. Therefore, it is anticipated that this positive revenue and margin trend will partially reverse in the fourth quarter.

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 tables detail the electric revenues and margin:

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2010				2009
Electric revenues		$	2,347			$	1,957
Electric fuel and purchased power			(1,162	)			(1,006	)
Electric margin		$	1,185			$	951

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

Electric Revenues

(Millions of Dollars)	2010 vs. 2009
Retail rate increase, including seasonal rates	$	177
Fuel and purchased power cost recovery		130
Renewable energy credit sales		26
Estimated impact of weather		18
DSM revenue and incentive (partially offset by expenses)		14
Trading		6
Retail sales increase (excluding weather impact)		5
Transmission revenues		4
Other, net		10
Total increase in electric revenues	$	390

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Electric Margin

(Millions of Dollars)	2010 vs. 2009
Retail rate increase, including seasonal rates	$	177
Estimated impact of weather		18
DSM revenue and incentive (partially offset by expenses)		14
Renewable energy credit sales		12
Firm wholesale		7
Retail sales increase (excluding weather impact)		5
Transmission revenues		4
Trading		(7	)
Other, net		4
Total increase in electric margin	$	234

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

·	A rate increase of $67 million was implemented on Jan. 1, 2010 because of the delay of the in-service date of Comanche Unit 3;

·	Base rates were increased to recover $123 million annually, on May 14, 2010 when Comanche Unit 3 went into service, including an additional $2 million of recovery for long-term debt interest in the working capital calculation granted under reconsideration; and

·	Base rates will increase to recover approximately $130 million annually on Jan. 1, 2011 to reflect 2011 property taxes.

A second phase of the rate case addressed changes to rate design. The new rates, approved by the CPUC, went into effect on June 1, 2010. In this phase of the proceeding, the CPUC approved tiered summer rates for residential customers and seasonally differentiated rates for other customer classes, which will impact the timing of revenue collection, as compared to the previous rate design, depending on customer response. Year to date electric revenue and margin for 2010 were positively impacted by approximately $53 million, related to the implementation of such rate design and seasonal rates. Seasonal rates are designed to be revenue neutral on an annual basis. However, the quarterly pattern of revenue collection is expected to be different than in the past as seasonal rates are higher in the summer months and lower throughout the remainder of the year. It is anticipated that this positive electric revenue and margin trend will partially reverse in the fourth quarter.

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the 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 tables detail natural gas revenues and margin:

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2010			2009
Natural gas revenues	$	733		$	678
Cost of natural gas sold and transported		(454	)		(416	)
Natural gas margin	$	279		$	262

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

Natural Gas Revenues

(Millions of Dollars)	2010 vs. 2009
Purchased natural gas cost recovery	$	38
Estimated impact of weather		8
DSM revenue and incentive (partially offset by expenses)		4
Other, net		5
Total increase in natural gas revenues	$	55

Natural Gas Margin

(Millions of Dollars)	2010 vs. 2009
Estimated impact of weather	$	8
DSM revenue and incentive (partially offset by expenses)		4
Other, net		5
Total increase in natural gas margin	$	17

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other O&M expenses increased by approximately $28.7 million, or 6.2 percent, for the first nine months of 2010, compared with the first nine months of 2009. The following summarizes the components of the changes for the nine months ended Sept. 30:

(Millions of Dollars)	2010 vs. 2009
Higher plant generation costs	$	11
Higher labor costs		5
Higher information technology costs		5
Higher contract labor costs		3
Lower employee benefit costs		(4	)
Other, net		9
Total increase in other operating and maintenance expenses	$	29

Higher plant generation costs are primarily attributable to higher levels of scheduled maintenance and overhaul work as well as incremental operating costs associated with new generation facilities placed in service in the current year.

Demand Side Management (DSM) Program Expenses — DSM program expenses increased by approximately $22.3 million, or 28.8 percent, for the first nine months of 2010, compared with the first nine months of 2009. The higher expense was primarily attributable to the expansion of programs and regulatory commitments. 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 $18.8 million, or 9.9 percent, for the first nine months of 2010, compared with the first nine months of 2009. The increase is primarily due to Comanche Unit 3 going into service and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $5.8 million, or 8.2 percent, for the first nine months of 2010, compared with the first nine months of 2009. The increase is primarily due to an increase in property taxes.

Other Income, Net — Other income, net increased by approximately $24.4 million for the first nine months of 2010, compared with the first nine months of 2009. The increase is primarily due to the COLI settlement in July 2010.

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Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased by approximately $31.0 million for the first nine months of 2010, compared with the first nine months of 2009. The decrease was partially due to recovery of Comanche Unit 3 financing costs through base rates and lower AFUDC rates.

Interest Charges — Interest charges increased by approximately $3.3 million, or 2.7 percent, for the first nine months of 2010, compared with the first nine months of 2009, primarily due to increased long-term borrowings.

Income Taxes — Income tax expense increased by $72.9 million for the first nine months of 2010, compared with the first nine months of 2009. The increase in income tax expense was primarily due to an increase in pretax income, a write-off of tax benefits previously recorded for Medicare Part D subsidies, and an adjustment at PSRI related to the COLI Tax Court proceedings. For further information, see Note 4 to the consolidated financial statements. The effective tax rate was 37.7 percent for the first nine months of 2010, compared with 34.4 percent for the same period in 2009. The higher effective tax rate for the first nine months of 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 nine months of 2010 would have been 34.2 percent.

Factors Affecting Results of Continuing Operations

Public Utility Regulation

Resource Plan — In October 2009, the CPUC approved the acquisitions of the resources identified in the bid evaluation report filed with the CPUC in August 2009. With minor modification, the CPUC adopted PSCo’s preferred plan, which includes an incremental 900 MW of additional intermittent renewable energy resources (wind and photovoltaic (PV) solar) and approximately 280 MW of “new technology” renewable energy sources. The CPUC approved the selection of about 900 MW of traditional gas-fired resources. The OCC has appealed the CPUC’s approval of the resource plan to Denver District Court, arguing that the CPUC erred in approving a portfolio where PSCo obtained an ownership interest in gas-fired generation and that this portfolio will not result in just and reasonable rates.

In May 2010, PSCo filed for approval to purchase approximately 900 MW of gas-fired generation from subsidiaries of Calpine Corporation consistent with the CPUC approved portfolio. PSCo has the ability to terminate the transaction if conditions on regulatory approval are unacceptable. The purchase is subject to federal and state regulatory approvals including approval of the proposed recovery of costs. In June 2010, the Federal Trade Commission provided notice of the early termination of the waiting period for premerger review. In July 2010, the FERC issued an order approving the acquisition.

In September 2010, PSCo reached partial settlement with CPUC staff, the Colorado Independent Energy Association and the OCC, which provided for recovery of the revenue requirement (capital and O&M costs) associated with the transaction through an interim rider mechanism less a $3.9 million annual revenue reduction until PSCo implements new retail base rates. Additionally, in its next retail rate case, PSCo shall be allowed recovery of the net book value, based on the $739 million purchase price.

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

San Luis Valley-Calumet-Comanche Unit 3 Transmission Project — PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a certificate of public convenience and necessity (CPCN) in May 2009. The project consists of four components of both 230 kilovolt (KV) and 345 KV line and substation construction. The line is intended to assist in bringing solar power in the San Luis Valley to load. The line was originally expected to be placed in-service in 2013; however, that appears unlikely now due to delays in the siting and permitting of the line. Several landowners are opposing this transmission line, including two large ranches. A recommended decision from the ALJ is pending.

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

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

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

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

In addition, distributed generation must equal:

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

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

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

The CPUC has discretion to review the reasonableness of the increase in the distributed generation percentage in 2014. PSCo believes that its forecasted plan acquisitions of renewable resources only need minor modification to comply with the new standard.

CACJA — The CACJA was signed into law in April 2010. The CACJA required PSCo to file a comprehensive plan with the CPUC by Aug. 15, 2010 to reduce annual emissions of NOx by at least 70 to 80 percent from 2008 levels from the coal-fired generation identified in the plan. The plan must consider emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by Jan. 1, 2018. The legislation further encourages PSCo to submit long-term gas contracts to the CPUC for approval. If approved, PSCo would be entitled to recover the costs it incurs under these long-term gas contracts, notwithstanding any change in the market price of natural gas during the term of the contract.

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

In August 2010, PSCo filed its preferred plan with the CPUC. PSCo’s recommended plan has three key components:

Retires 900 MW of coal generation at its Valmont (186 MW) and Cherokee (717 MW) power plants by the end of 2017 and the end of 2022, respectively;

Repowers its Cherokee generating facility with efficient, natural gas generation of 883 MW (589 MW in 2015 and 314 MW in 2022). PSCo also will switch to natural gas generation at the 111 MW Arapahoe Unit 4 generating facility in 2013; and

Retrofits about 950 MW of coal-fired generation at the Pawnee (505 MW) and Hayden (446 MW) generating facilities with modern emission control technology.

The plan would reduce emissions of NOx from the targeted plants by 77 percent at the end 2017, and by 89 percent at the end of 2022. In addition, when compared to 2008 levels, the plan would reduce sulfur dioxide emissions by 84 percent and mercury emissions by 85 percent for the power plants targeted under the plan by 2023. The plan also allows PSCo to meet Colorado’s statewide carbon dioxide reduction goal of 20 percent before the 2020 target.

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The total cost of the plan, if approved by the CPUC, would result in new construction of approximately $1.4 billion over the next 12 years. The rate impact of the proposed plan is expected to increase future bills on average by 1.5 percent annually over the next ten years. The recommended plan costs less than retrofitting all of these units with emission control equipment. The estimated cost of the plan for the years 2011 through 2017 is shown in the table below:

(Millions of Dollars)	2011		2012		2013		2014		2015		2016		2017		Total
Combined cycle	$	16.0	$	81.0	$	203.1	$	105.4	$	103.1	$	25.9	$	-	$	534.5
Pollution control unit		69.6		82.8		66.3		93.4		26.1		8.6		-		346.8
Transmission		1.2		3.1		3.1		4.5		11.4		-		-		23.3
Gas pipeline		5.9		6.1		57.2		40.7		-		-		-		109.9
Total	$	92.7	$	173.0	$	329.7	$	244.0	$	140.6	$	34.5	$	-	$	1,014.5

PSCo also proposed to implement a new emission reduction adjustment rate to go into effect around January 2011. This adjustment clause seeks to recover a return on the CWIP for electric investments made pursuant to the plan and also includes the recovery of other plant related costs, such as higher depreciation expense, incurred under the emissions reduction plan. The 2011 expected increase would be approximately $14.1 million.

In September 2010, 51 witnesses filed answer testimony representing over 20 parties in the case. Coal interests generally opposed PSCo’s plan and advocated for scenarios in which emissions control retrofits were installed. Gas interests and environmental groups advocated for accelerating the time line of PSCo’s proposed plan and advocated for the inclusion of other generation alternatives and energy efficiency. The City and County of Denver, Colo. and the County of Boulder, Colo. supported the plan. Several parties sought changes to the regulatory recovery provisions proposed by PSCo. Hearings began on Oct. 21, 2010, and the CPUC is scheduled to issue a decision by Dec. 15, 2010.

In October 2010, the CPUC ruled that based on the Colorado Department of Public Health and Environment’s (CDPHE) interpretation of certain statutory provisions related to reasonably foreseeable air quality regulations, that PSCo’s plan to take actions beyond 2017 failed to meet the standards of the CACJA. As a result, PSCo filed supplemental testimony on Oct. 25, 2010 recommending that if the CPUC or the CDPHE can’t find the original plan acceptable, that the preferred plan is to install selective catalytic reduction on its Cherokee Unit 4 by 2017.

SmartGridCity™ CPCN — As part of the recent PSCo electric rate case, the CPUC included recovery of the revenue requirements associated with the capital and O&M costs incurred by PSCo to develop and operate SmartGridCity™, subject to refund, and ordered PSCo to file for a CPCN for that project. PSCo is currently recovering the revenue requirements on $42 million of capital costs and $4 million in annual O&M expenses.

In March 2010, PSCo filed the required CPCN. Intervenors filed testimony in July 2010. Two parties, Leslie Glustrom and ArapaHope Community Team (ACT) oppose issuance of the CPCN. The OCC and Glustrom recommended partial recovery of capital costs while ACT recommended no recovery. ACT withdrew from the case before hearing. The OCC recommended recovery of revenue requirements of $27.9 million of capital costs. PSCo reached a settlement with the CPUC staff and the Governor's Energy Office for approval of the CPCN and cost recovery. PSCo is awaiting a recommended decision from the ALJ.

Summary of Recent Federal Regulatory Developments

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

Electric Reliability Standards Compliance

Compliance Audits

In 2008, PSCo was subject to an audit of its compliance with the NERC and regional reliability standards by the Western Electricity Coordinating Council (WECC), the NERC regional entity for the PSCo system. On Oct. 31, 2008, the WECC auditors issued their final audit report on PSCo’s compliance with electric reliability standards. The report found a possible violation of one reliability standard related to relay maintenance.

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In 2008, PSCo filed self-reports with the WECC relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain critical infrastructure protection (CIP) standards. In 2009, PSCo reached agreement with the WECC that would resolve the open 2008 audit finding and the 2008 self reports by payment of a non-material penalty. In February 2010, PSCo executed a definitive settlement agreement. This settlement agreement is pending approval by the NERC and will also need to be approved by the FERC.

In March 2010, the WECC conducted a compliance spot check to evaluate compliance with the NERC CIP standards, which were effective July 1, 2008. The draft non-public report issued in July 2010 found that the Xcel Energy utility subsidiaries may not be in compliance with several of the CIP standards. Xcel Energy, the parent company of PSCo, provided comments on the draft report. The regional entity audit function issued a non-public final report in August 2010 alleging violations of certain CIP requirements, including certain violations common to all Xcel Energy utility subsidiaries; at that time, the spot check report was transferred to the MRO enforcement function. Xcel Energy continues to dispute the alleged violations and is working to resolve issues with the MRO enforcement functions. To what extent the regional entities or NERC may seek to impose penalties for violations of CIP standards is unknown at this time.

In July 2010, the WECC issued a non-public notice of alleged violation (NAV) related to (1) two alleged non-common CIP violations identified in the joint CIP spot-check, and (2) two violations self-reported by PSCo in February 2010 related to certain balancing authority (BAL) standards. The WECC NAV proposed a non-material penalty. PSCo requested that the proceedings be deferred to allow settlement negotiations to resolve the NAV. The matter is now in settlement discussions.

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 Sept. 30, 2010, 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 financial statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Notes 14 and 15 of PSCo’s consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2009 for a description of certain legal proceedings presently pending.

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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, 2009, which is incorporated herein by reference.

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

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

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

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

Item 6 — Exhibits

_________________________

* Indicates incorporation by reference

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.

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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
	(Registrant)

Oct. 29, 2010	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Vice President and Controller

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

Attached files

PUBLIC SERVICE CO OF COLORADO Reports

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