UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

or

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

Commission File Number: 001-3280

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

Colorado	84-0296600
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1800 Larimer, Suite 1100
Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

Class	Outstanding at Oct. 29, 2012
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	23
Item 4 —	Controls and Procedures	28
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	28
Item 1A —	Risk Factors	28
Item 4 —	Mine Safety Disclosures	29
Item 5 —	Other Information	29
Item 6 —	Exhibits	29
SIGNATURES		30
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

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

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2012			2011			2012			2011
Operating revenues
Electric	$	870,975		$	933,490		$	2,267,905		$	2,387,434
Natural gas		113,230			122,672			643,632			725,593
Steam and other		8,082			7,772			26,303			28,454
Total operating revenues		992,287			1,063,934			2,937,840			3,141,481
Operating expenses
Electric fuel and purchased power		315,319			413,093			920,916			1,089,106
Cost of natural gas sold and transported		24,662			51,104			338,630			450,064
Cost of sales — steam and other		3,650			3,793			10,745			12,903
Operating and maintenance expenses		180,994			183,152			529,476			540,491
Demand side management program expenses		33,670			29,796			92,462			87,885
Depreciation and amortization		85,905			85,146			249,645			245,392
Taxes (other than income taxes)		32,696			31,428			99,359			100,734
Total operating expenses		676,896			797,512			2,241,233			2,526,575
Operating income		315,391			266,422			696,607			614,906
Other income, net		1,000			1,806			3,582			5,704
Allowance for funds used during construction —  equity		4,687			1,956			10,961			5,373
Interest charges and financing costs
Interest charges — includes other financing costs of
$1,803, $1,798, $5,383 and $5,074, respectively		49,369			46,955			145,734			138,390
Allowance for funds used during construction — debt		(2,633	)		(853	)		(5,328	)		(2,399	)
Total interest charges and financing costs		46,736			46,102			140,406			135,991
Income before income taxes		274,342			224,082			570,744			489,992
Income taxes		81,899			83,364			189,609			181,626
Net income	$	192,443		$	140,718		$	381,135		$	308,366

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2012			2011			2012			2011
Net income	$	192,443		$	140,718		$	381,135		$	308,366
Other comprehensive loss
Derivative instruments:
Net fair value decrease, net of tax of $(2,197), $(8,839),
$(5,710) and $(8,788), respectively		(3,574	)		(14,428	)		(9,311	)		(14,346	)
Reclassification of gains to net income, net of tax of
$(186), $(233), $(646) and $(691), respectively		(304	)		(381	)		(1,055	)		(1,127	)
		(3,878	)		(14,809	)		(10,366	)		(15,473	)
Other comprehensive loss		(3,878	)		(14,809	)		(10,366	)		(15,473	)
Comprehensive income	$	188,565		$	125,909		$	370,769		$	292,893

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)

	Nine Months Ended Sept. 30
	2012			2011
Operating activities
Net income	$	381,135		$	308,366
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		253,764			249,396
Demand side management program amortization		4,042			6,484
Deferred income taxes		179,254			183,918
Amortization of investment tax credits		(1,955	)		(2,002	)
Allowance for equity funds used during construction		(10,961	)		(5,373	)
Net realized and unrealized hedging and derivative transactions		(39,241	)		16,789
Changes in operating assets and liabilities:
Accounts receivable		50,612			12,232
Accrued unbilled revenues		110,880			77,382
Inventories		11,553			(38,563	)
Prepayments and other		(33,967	)		28,297
Accounts payable		(83,400	)		(38,903	)
Net regulatory assets and liabilities		(66,007	)		14,038
Other current liabilities		(8,444	)		2,508
Pension and other employee benefit obligations		(59,154	)		(60,047	)
Change in other noncurrent assets		(8,730	)		3,467
Change in other noncurrent liabilities		(505	)		(13,108	)
Net cash provided by operating activities		678,876			744,881
Investing activities
Utility capital/construction expenditures		(610,309	)		(475,444	)
Allowance for equity funds used during construction		10,961			5,373
Investments in utility money pool arrangement		(820,000	)		(268,300	)
Repayments from utility money pool arrangement		752,000			199,300
Net cash used in investing activities		(667,348	)		(539,071	)
Financing activities
Repayments of short-term borrowings, net		-			(269,400	)
Borrowings under utility money pool arrangement		36,000			203,800
Repayments under utility money pool arrangement		(36,000	)		(203,800	)
Proceeds from issuance of long-term debt		791,007			246,602
Capital contributions from parent		28,122			76,221
Dividends paid to parent		(200,501	)		(202,636	)
Net cash provided by (used in) financing activities		618,628			(149,213	)
Net change in cash and cash equivalents		630,156			56,597
Cash and cash equivalents at beginning of period		3,763			32,912
Cash and cash equivalents at end of period	$	633,919		$	89,509
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(133,667	)	$	(125,727	)
Cash (paid) received for income taxes, net		(51,240	)		30,575
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	79,597		$	102,078

See Notes to Consolidated Financial Statements

5

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	Sept. 30, 2012			Dec. 31, 2011
Assets
Current assets
Cash and cash equivalents	$	633,919		$	3,763
Accounts receivable, net		265,144			317,039
Accounts receivable from affiliates		13,346			12,063
Investments in utility money pool arrangement		120,000			52,000
Accrued unbilled revenues		193,664			304,544
Inventories		242,444			253,997
Regulatory assets		156,906			196,311
Deferred income taxes		41,443			33,349
Derivative instruments		6,403			4,930
Prepayments and other		53,471			19,504
Total current assets		1,726,740			1,197,500
Property, plant and equipment, net		9,844,906			9,475,571
Other assets
Regulatory assets		793,037			809,011
Derivative instruments		11,957			15,357
Other		49,561			36,066
Total other assets		854,555			860,434
Total assets	$	12,426,201		$	11,533,505
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	856,122		$	605,633
Accounts payable		321,702			362,580
Accounts payable to affiliates		26,352			48,371
Regulatory liabilities		26,378			68,809
Taxes accrued		100,348			116,376
Accrued interest		56,066			53,749
Dividends payable to parent		66,470			66,926
Derivative instruments		8,408			85,518
Other		75,782			75,671
Total current liabilities		1,537,628			1,483,633
Deferred credits and other liabilities
Deferred income taxes		1,963,501			1,775,448
Deferred investment tax credits		42,770			44,725
Regulatory liabilities		414,801			444,442
Asset retirement obligations		44,001			42,207
Derivative instruments		32,443			38,325
Customer advances		230,029			226,097
Pension and employee benefit obligations		163,396			222,707
Other		68,444			69,561
Total deferred credits and other liabilities		2,959,385			2,863,512
Commitments and contingencies
Capitalization
Long-term debt		3,424,623			2,880,642
Common stock – 100 shares authorized at $0.01 par value; 100 shares
outstanding at Sept. 30, 2012 and Dec. 31, 2011		-			-
Additional paid in capital		3,344,508			3,316,386
Retained earnings		1,182,800			1,001,709
Accumulated other comprehensive loss		(22,743	)		(12,377	)
Total common stockholder's equity		4,504,565			4,305,718
Total liabilities and equity	$	12,426,201		$	11,533,505

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, 2012 and Dec. 31, 2011; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2012 and 2011; and its cash flows for the nine months ended Sept. 30, 2012 and 2011.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after Sept. 30, 2012 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, 2011 balance sheet information has been derived from the audited 2011 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2011.  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 on an annual basis 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, 2011, filed with the SEC on Feb. 27, 2012.  Due to the seasonality of PSCo’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2011, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Adopted

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  PSCo implemented the accounting and disclosure guidance effective Jan. 1, 2012, and the implementation did not have a material impact on its consolidated financial statements.  For required fair value measurement disclosures, see Note 8.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which requires the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial statements of net income and comprehensive income.  These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  PSCo implemented the financial statement presentation guidance effective Jan. 1, 2012.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  PSCo does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

7

3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2012			Dec. 31, 2011
Accounts receivable, net
Accounts receivable	$	287,169		$	341,737
Less allowance for bad debts		(22,025	)		(24,698	)
	$	265,144		$	317,039

(Thousands of Dollars)	Sept. 30, 2012		Dec. 31, 2011
Inventories
Materials and supplies	$	53,851	$	53,318
Fuel		96,647		94,874
Natural gas		91,946		105,805
	$	242,444	$	253,997

(Thousands of Dollars)	Sept. 30, 2012			Dec. 31, 2011
Property, plant and equipment, net
Electric plant	$	9,741,933		$	9,469,434
Natural gas plant		2,535,274			2,456,275
Common and other property		748,553			763,513
Plant to be retired (a)		105,573			151,184
Construction work in progress		490,561			242,095
Total property, plant and equipment		13,621,894			13,082,501
Less accumulated depreciation		(3,776,988	)		(3,606,930	)
	$	9,844,906		$	9,475,571

(a) In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the Colorado Public Utilities Commission (CPUC) approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017.  In 2011, Cherokee Unit 2 was retired, and in May 2012, Cherokee Unit 1 was retired.  Amounts are presented net of accumulated depreciation.

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in September 2013.  In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Sept. 30, 2012, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006.  As of Sept. 30, 2012, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	Sept. 30, 2012		Dec. 31, 2011
Unrecognized tax benefit — Permanent tax positions	$	1.4	$	0.5
Unrecognized tax benefit — Temporary tax positions		8.8		10.9
Total unrecognized tax benefit	$	10.2	$	11.4

8

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

(Millions of Dollars)	Sept. 30, 2012			Dec. 31, 2011
NOL and tax credit carryforwards	$	(6.1	)	$	(3.7	)

It is reasonably possible that 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, an overall range of possible change cannot be reasonably estimated.  

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.  The payables for interest related to unrecognized tax benefits at Sept. 30, 2012 and Dec. 31, 2011 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2012 or Dec. 31, 2011.

Impact of the Patient Protection and Affordable Care Act — 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.

In the third quarter of 2012, PSCo implemented a tax strategy related to the allocation of funding of PSCo’s retiree prescription drug plan.  This strategy restored a portion of the tax benefit associated with federal subsidies for prescription drug plans that had been accrued since 2004 and was expensed in 2010.  As a result, PSCo recognized approximately $17 million of income tax benefit.

5.  Rate Matters

Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Recently Concluded Regulatory Proceedings — CPUC

2011 Electric Rate Case —In November 2011, PSCo filed a request with the CPUC to increase Colorado retail electric rates by $141.9 million.  The request was based on a 2012 forecast test year, a 10.75 percent return on equity (ROE), an electric rate base of $5.4 billion and an equity ratio of 56 percent.

In April 2012, the CPUC approved a comprehensive multi-year settlement agreement, which covers 2012 through 2014.  Key terms of the agreement include the following:

· PSCo would implement an annual electric rate increase of $73 million in 2012.  The rate increase was effective on May 1, 2012.  In addition, PSCo will implement incremental electric rate increases of $16 million on Jan. 1, 2013 and $25 million on Jan. 1, 2014.  These rate increases are net of the shift of the costs from the purchased capacity cost adjustment and the transmission cost adjustment clauses to base rates.

· The settlement reflects an authorized ROE of 10 percent and an equity ratio of 56 percent.

· For 2012 through 2014, incremental property taxes in excess of $76.7 million (2010-2011 historic test year property taxes) will be deferred over a three-year period with the amortization effective the first year after the deferral.  To the extent that PSCo is successful in gaining the manufacturer’s sales tax refund as a result of the sales tax lawsuit currently pending in the Colorado Supreme Court, PSCo will credit such refunds first against legal fees incurred to obtain the refund and then against the deferred property tax balances outstanding at the end of the 2014.

· The signing parties agreed to implement an earnings test, in which customers and shareholders will share weather normalized earnings above an ROE of 10 percent.  The sharing mechanism is as follows:

ROE	Shareholders			Customers
> 10.0% < 10.2%		40	%		60	%
> 10.2% < 10.5%		50			50
> 10.5%		-			100

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· PSCo agreed that it will not file for an electric rate increase that would take effect prior to Jan. 1, 2015, provided that net revenue requirements increase or decrease in excess of $10 million caused by changes in tax law, government mandates, or natural disasters may be deferred or recovered through a modified rate adjustment.  In the event normalized base revenues in either 2012 or 2013 are 2.0 percent below 2011 actual levels adjusted to reflect the rate increases allowed for 2012 and 2013, PSCo has the right to an additional rate adjustment in the next year for 50 percent of the shortfall.  The parties acknowledged that PSCo may file an electric rate increase as early as May 1, 2014, so long as no rate increase takes effect on either an interim or permanent basis prior to Jan. 1, 2015.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing — In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014.  The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers’ share of the margins to be netted against the renewable energy standard adjustment (RESA) regulatory asset balance.  In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

In March 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo.  Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo.  The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance.  In March 2012, PSCo credited approximately $28.7 million against the RESA regulatory asset balance.  PSCo has continued to credit the customer share of REC margins to the RESA regulatory asset balance each month.  As of Sept. 30, 2012, PSCo has credited $41.2 million.

This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and to review evidence regarding actual deliveries in relatively more complex markets such as California.

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

Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from a historic test year formula rate to a forecast transmission formula rate and to establish formula ancillary services rates.  PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up.  The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million annually.  Various transmission customers taking service under the tariff protested the filing.  In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to Nov. 17, 2012, subject to refund, and setting the case for settlement judge or hearing procedures.  PSCo has been engaged in discovery and initial settlement discussions with the intervenors and the FERC Staff.

Separately, several wholesale customers filed a complaint with the FERC in June 2012 seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012.  If implemented, the ROE reduction would reduce PSCo transmission and ancillary rate revenues by approximately $1.8 million annually.  On Oct. 5, 2012, the FERC issued an order accepting the complaint, consolidating the complaint with the April 2012 formula rate change filing, establishing a refund effective date of July 1, 2012, and setting the complaint for settlement judge and hearing procedures.  The settlement discussions are now expected to seek to resolve both dockets.  If PSCo, the FERC and intervenors do not reach settlement, the dockets would proceed to a contested hearing.

6. Commitments and Contingencies

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 11 and 12 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2011, 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.

Purchased Power Agreements

Under certain purchased power agreements, PSCo purchases power from independent power producing entities for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases.  These specific purchased power agreements create a variable interest in the associated independent power producing entity.

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PSCo had approximately 1,433 megawatts (MW) and 1,882 MW of capacity under long-term purchased power agreements as of Sept. 30, 2012 and Dec. 31, 2011, respectively, with entities that have been determined to be variable interest entities.  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.  These agreements have expiration dates through the year 2028.

Indemnifications

In connection with the acquisition of 900 MW of natural gas-fired generation from subsidiaries of Calpine Development Holdings Inc. in 2010, PSCo agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  The aggregate liability for PSCo pursuant to these indemnities is not subject to a capped dollar amount.  The indemnification obligation expires in December 2012.  PSCo has not recorded a liability related to this indemnity, and it had no assets held as collateral related to this agreement at Sept. 30, 2012 or Dec. 31, 2011.

Environmental Contingencies

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the U.S. Environmental Protection Agency (EPA) proposed a GHG NSPS for newly constructed power plants.  The proposal requires that carbon dioxide (CO2) emission rates be equal to those achieved by a natural gas combined-cycle plant, even if the plant is coal-fired.  The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and that installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program.  Xcel Energy submitted comments on the proposed GHG NSPS in June 2012.  It is not possible to evaluate the impact of this regulation until its final requirements are known.

The EPA also plans to propose GHG regulations applicable to emissions from existing power plants under the Clean Air Act (CAA).  It is not known when the EPA will propose new standards for existing sources.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective April 2012.  The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date.  PSCo expects to comply with the EGU MATS rule through emission control projects associated with the CACJA.  PSCo believes these costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

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

In 2006, the Colorado Air Quality Control Commission (CAQCC) promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal.  In January 2011, the CAQCC approved a revised regional haze BART state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements.  The Colorado legislature enacted a statute approving the SIP, which was signed into law in 2011.  Subsequently, the Colorado Mining Association (CMA) challenged the SIP in a Colorado District Court.  In June 2012, the CMA’s appeal was dismissed due to the legislative approval given to the SIP after the CAQCC approval.  The CMA appealed this decision to the Colorado Court of Appeals in August 2012.

In September 2012, the EPA granted final approval of the Colorado SIP, including the CACJA emission reduction plan for PSCo, as satisfying BART requirements.  The emission controls are expected to be installed between 2014 and 2017.  Projected costs for emission controls at the Hayden and Pawnee plants are $334.2 million.  PSCo expects the cost of any required capital investment will be recoverable from customers through the CACJA emission reduction plan recovery mechanisms or other regulatory mechanisms.

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

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In June 2012, the EPA proposed to lower the primary (health-based) NAAQS for annual average fine PM and to retain the current daily standard for fine PM.  In areas in which PSCo operates power plants, current monitored air concentrations are below the range of the proposed annual primary standard.  The EPA also proposed to add a secondary (welfare-based) NAAQS to improve visibility, primarily in urban areas.  PSCo expects the proposed visibility standard would likely be met where PSCo operates power plants based on currently available information.  A final rule is expected in December 2012 and the EPA is expected to designate non-compliant locations by December 2014.  If such areas are identified, states would then study the sources of the nonattainment and make emission reduction plans to attain the standards.  It is not possible to evaluate the impact of this regulation further until its final requirements are known.

Legal Contingencies

PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business.  The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation.  Management is sometimes unable to estimate an amount or range of a reasonably possible loss, in certain situations, including but not limited to where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.  In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.  For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements.

Environmental Litigation

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in the U.S. District Court for the Northern District of California against Xcel Energy Inc., the parent company of PSCo, and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).  In October 2012 the Ninth Circuit affirmed the U.S. District Court’s dismissal.  On Oct.14, 2012, plaintiffs filed a petition for rehearing en banc.  It is uncertain when the Ninth Circuit will respond to this petition.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina.  Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million.  Although Xcel Energy Inc. believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in the U.S. District Court in Mississippi.  The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc. and PSCo.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.  Although Xcel Energy Inc. believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

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Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001.  PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings.  In September 2001, the presiding administrative law judge (ALJ) concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices.  Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered.  Subsequent to the ruling, the FERC has allowed the parties to request additional evidence.  Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million.  In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings.  Certain purchasers filed appeals of the FERC’s orders in this proceeding with the U.S. Court of Appeals for the Ninth Circuit.

In an order issued in August 2007, the U.S. Court of Appeals for the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets.  The U.S. Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued. 

The FERC has issued an order on remand establishing principles for the review proceeding in October 2011.  In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers and has expanded the period for which it seeks refunds to May 2000 through June 2001, during which PSCo had sales to the City of Seattle of approximately $50 million.  The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets.  Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million not including interest.  PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  In making this assessment, PSCo considered two factors:  PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and that the FERC’s standard will likely be challenged on appeal to the U.S. Court of Appeals for the Ninth Circuit.  PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions.  In addition, if a loss were sustained, PSCo would attempt to recover those losses from other potentially responsible parties.  No accrual has been recorded for this matter.

7.  Borrowings and Other Financing Instruments

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended  Sept. 30, 2012			Twelve Months Ended  Dec. 31, 2011
Borrowing limit	$	700		$	700
Amount outstandingat period end		-			-
Average amount outstanding		6			73
Maximum amount outstanding		46			304
Weighted average interest rate, computed on a daily basis		0.30	%		0.37	%
Weighted average interest rate at period end		N/A			N/A

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, 2012 and Dec. 31, 2011, there were $3.9 million and $4.9 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.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility.  The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At Sept. 30, 2012, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility		Drawn (a)		Available
$	700.0	$	3.9	$	696.1

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

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All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  PSCo had no direct advances on the credit facility outstanding at Sept. 30, 2012 and Dec. 31, 2011.

Amended Credit Agreement — In July 2012, PSCo entered into an amended five-year credit agreement with a syndicate of banks, replacing the previous four-year credit agreement.  The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an improvement in pricing and an extension of maturity from March 2015 to July 2017.  The Eurodollar borrowing margin on the line of credit was reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings.  The commitment fees, calculated on the unused portion of the line of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

PSCo has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries.  Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.  The following table presents the money pool borrowings for PSCo:

(Amounts in Millions, Except Interest Rates)	Three Months Ended  Sept. 30, 2012			Twelve Months Ended  Dec. 31, 2011
Borrowing limit	$	250		$	250
Amount outstandingat period end		-			-
Average amount outstanding		1			3
Maximum amount outstanding		8			53
Weighted average interest rate, computed on a daily basis		0.32	%		0.35	%
Weighted average interest rate at period end		N/A			N/A

Long-Term Borrowings

In September 2012, PSCo issued $300 million of 2.25 percent first mortgage bonds due Sept. 15, 2022, as well as $500 million of 3.60 percent first mortgage bonds due Sept. 15, 2042.  PSCo used a portion of the net proceeds from the first mortgage bonds to redeem $600 million of 7.875 percent first mortgage bonds maturing on Oct. 1, 2012, and intends to redeem $48.75 million of 5.10 percent bonds due Jan. 1, 2019, for which a notice of full optional redemption was issued to bondholders on Oct. 1, 2012.

8.  Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value.  A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.  The three levels in the hierarchy are as follows:

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

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

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

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Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2.  When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. 

PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivatives prior to settlement, 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 derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

Derivative Instruments Fair Value Measurements

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

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

At Sept. 30, 2012, accumulated other comprehensive losses related to interest rate derivatives included $0.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

In conjunction with the PSCo debt issuance in September 2012, PSCo settled interest rate hedging instruments with a notional amount of $250 million during the three months ended Sept. 30, 2012 with cash payments of $44.7 million.  These losses are classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and will be reclassified to earnings over the term of the hedged interest payments.  See Note 7 for further discussion of long-term borrowings.

Wholesale and Commodity Trading Risk — PSCo conducts various 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 this policy.

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

At Sept. 30, 2012, PSCo had various vehicle fuel related contracts designated as cash flow hedges extending through December 2016.  PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and nine months ended Sept. 30, 2012 and 2011.

At Sept. 30, 2012, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers.  Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of any amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards and options at Sept. 30, 2012 and Dec. 31, 2011:

(Amounts in Thousands) (a)(b)	Sept. 30, 2012		Dec. 31, 2011
Megawatt hours (MWh) of electricity		973		1,299
MMBtu of natural gas		6,932		32,053
Gallons of vehicle fuel		329		270

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

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

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

	Three Months Ended Sept. 30
(Thousands of Dollars)	2012			2011
Accumulated other comprehensive (loss) income related to cash flow hedges at July 1	$	(18,865	)	$	6,793
After-tax net unrealized losses related to derivatives accounted for as hedges		(3,574	)		(14,428	)
After-tax net realized gains on derivative transactions reclassified into earnings		(304	)		(381	)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(22,743	)	$	(8,016	)

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2012			2011
Accumulated other comprehensive (loss) income related to cash flow hedges at Jan. 1	$	(12,377	)	$	7,457
After-tax net unrealized losses related to derivatives accounted for as hedges		(9,311	)		(14,346	)
After-tax net realized gains on derivative transactions reclassified into earnings		(1,055	)		(1,127	)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(22,743	)	$	(8,016	)

The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2012 and 2011, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 2012
	Fair Value Gains (Losses)					Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in					into Income During the Period from
	Accumulated					Accumulated						Pre-Tax Gains
	Other			Regulatory		Other				Regulatory		Recognized
	Comprehensive			(Assets) and		Comprehensive				Assets and		During the Period
(Thousands of Dollars)	Loss			Liabilities		Loss				(Liabilities)		in Income
Derivatives designated as cash flow hedges
Interest rate	$	(5,836	)	$	-	$	(470	)	(a)	$	-	$	-
Vehicle fuel and other commodity		65			-		(20	)	(e)		-		-
Total	$	(5,771	)	$	-	$	(490	)		$	-	$	-
Other derivative instruments
Trading commodity	$	-		$	-	$	-			$	-	$	1	(b)
Natural gas commodity		-			1,109		-				-		-
Total	$	-		$	1,109	$	-			$	-	$	1

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	Nine Months Ended Sept. 30, 2012
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated							Pre-Tax Gains
	Other			Regulatory			Other				Regulatory			(Losses) Recognized
	Comprehensive			(Assets) and			Comprehensive				Assets and			During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss				(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(15,082	)	$	-		$	(1,635	)	(a)	$	-		$	-
Vehicle fuel and other commodity		61			-			(66	)	(e)		-			-
Total	$	(15,021	)	$	-		$	(1,701	)		$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-			$	-		$	2		(b)
Natural gas commodity		-			(5,837	)		-				61,858	(d)		(109	)	(c)
Total	$	-		$	(5,837	)	$	-			$	61,858		$	(107	)

	Three Months Ended Sept. 30, 2011
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated							Pre-Tax Losses
	Other			Regulatory			Other				Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive				Assets and			During the Period
(Thousands of Dollars)	Income			Liabilities			Income				(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(23,178	)	$	-		$	(589	)	(a)	$	-		$	-
Vehicle fuel and other commodity		(89	)		-			(25	)	(e)		-			-
Total	$	(23,267	)	$	-		$	(614	)		$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-			$	-		$	(12	)	(b)
Natural gas commodity		-			(31,802	)		-				308	(d)		(126	)	(c)
Total	$	-		$	(31,802	)	$	-			$	308		$	(138	)

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	Nine Months Ended Sept. 30, 2011
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated							Pre-Tax Gains
	Other			Regulatory			Other				Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive				Assets and			During the Period
(Thousands of Dollars)	Income			Liabilities			Income				(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(23,178	)	$	-		$	(1,748	)	(a)	$	-		$	-
Vehicle fuel and other commodity		44			-			(70	)	(e)		-			-
Total	$	(23,134	)	$	-		$	(1,818	)		$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-			$	-		$	83		(b)
Natural gas commodity		-			(44,948	)		-				45,527	(d)		(126	)	(c)
Total	$	-		$	(44,948	)	$	-			$	45,527		$	(43	)

(a) Amounts are recorded to interest charges.

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

(c) Amounts are recorded to electric fuel and purchased power.

(d) Amounts for the nine months ended Sept. 30, 2012 and 2011 include $5.0 million and $9.9 million of settlement losses, respectively, on derivatives utilized to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.  The remaining settlement losses for the nine months ended Sept. 30, 2012 and 2011, and all settlement losses for the three months ended Sept. 30, 2012 and 2011, relate to natural gas operations and are recorded to cost of natural gas sold and transported.  These losses are subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.

(e) Amounts are recorded to operating and maintenance (O&M) expenses.

PSCo had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2012 and Sept. 30, 2011.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features —Contract provisions of the derivative instruments that PSCo enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale (NPNS) contracts and therefore not reflected on the balance sheet, 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, derivative instruments reflected in a $5.4 million and $6.9 million gross liability position on the consolidated balance sheets at Sept. 30, 2012 and Dec. 31, 2011, respectively, would have required PSCo to post collateral or settle outstanding contracts, including NPNS contracts, which would have resulted in payments of $5.4 million and $9.2 million at Sept. 30. 2012 and Dec. 31, 2011, respectively, inclusive of the impacts of offsetting asset positions with the applicable counterparties.  At Sept. 30 2012 and Dec. 31, 2011, there was no collateral posted on these specific contracts.

Certain 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 PSCo’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, 2012 and Dec. 31, 2011.

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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, 2012:

	Sept. 30, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	60	$	-	$	60	$	-		$	60
Other derivative instruments:
Trading commodity		-		5,899		-		5,899		(3,150	)		2,749
Natural gas commodity		-		1,878		-		1,878		-			1,878
Total current derivative assets	$	-	$	7,837	$	-	$	7,837	$	(3,150	)		4,687
Purchased power agreements (a)													1,716
Current derivative instruments												$	6,403
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	62	$	-	$	62	$	-		$	62
Other derivative instruments:
Trading commodity		-		4,710		-		4,710		(1,852	)		2,858
Total noncurrent derivative assets	$	-	$	4,772	$	-	$	4,772	$	(1,852	)		2,920
Purchased power agreements (a)													9,037
Noncurrent derivative instruments												$	11,957
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Trading commodity	$	-	$	5,425	$	-	$	5,425	$	(2,445	)	$	2,980
Total current derivative liabilities	$	-	$	5,425	$	-	$	5,425	$	(2,445	)		2,980
Purchased power agreements (a)													5,428
Current derivative instruments												$	8,408
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	4,237	$	-	$	4,237	$	(1,852	)	$	2,385
Total noncurrent derivative liabilities	$	-	$	4,237	$	-	$	4,237	$	(1,852	)		2,385
Purchased power agreements (a)													30,058
Noncurrent derivative instruments												$	32,443

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

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

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The following table presents for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	76	$	-	$	76	$	(76	)	$	-
Other derivative instruments:
Trading commodity		-		6,550		-		6,550		(3,712	)		2,838
Total current derivative assets	$	-	$	6,626	$	-	$	6,626	$	(3,788	)		2,838
Purchased power agreements (a)													2,092
Current derivative instruments												$	4,930
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	48	$	-	$	48	$	-		$	48
Other derivative instruments:
Trading commodity		-		8,292		-		8,292		(3,305	)		4,987
Total noncurrent derivative assets	$	-	$	8,340	$	-	$	8,340	$	(3,305	)		5,035
Purchased power agreements (a)													10,322
Noncurrent derivative instruments												$	15,357
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	29,630	$	-	$	29,630	$	-		$	29,630
Other derivative instruments:
Trading commodity		-		6,076		-		6,076		(2,846	)		3,230
Natural gas commodity		-		54,525		-		54,525		(7,410	)		47,115
Total current derivative liabilities	$	-	$	90,231	$	-	$	90,231	$	(10,256	)		79,975
Purchased power agreements (a)													5,543
Current derivative instruments												$	85,518
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	7,502	$	-	$	7,502	$	(3,305	)	$	4,197
Total noncurrent derivative liabilities	$	-	$	7,502	$	-	$	7,502	$	(3,305	)		4,197
Purchased power agreements (a)													34,128
Noncurrent derivative instruments												$	38,325

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

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

There were no changes in Level 3 recurring fair value measurements for the three and nine months ended Sept. 30, 2012 and 2011.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for the three and nine months ended Sept. 30, 2012 and 2011.

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Fair Value of Long-Term Debt

As of Sept. 30, 2012 and Dec. 31, 2011, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2012				Dec. 31, 2011
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	4,280,745	$	4,825,506	$	3,486,275	$	4,020,083

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of Sept. 30, 2012 and Dec. 31, 2011, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since those dates and current estimates of fair values may differ significantly.

9. Other Income, net

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

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2012			2011			2012			2011
Interest income	$	909		$	906		$	2,709		$	3,599
Other nonoperating income		441			619			1,807			1,972
Insurance policy (expense) income		(350	)		283			(934	)		142
Other nonoperating expense		-			(2	)		-			(9	)
Other income, net	$	1,000		$	1,806		$	3,582		$	5,704

10.  Segment Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker.  PSCo evaluates performance based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each reportable segment.

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

· PSCo’s regulated electric utility segment generates electricity which is transmitted and distributed in Colorado.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.  Regulated electric utility also includes PSCo’s commodity trading operations.

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

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

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.

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	Regulated		Regulated			All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas			Other		Eliminations			Total
Three Months Ended Sept. 30, 2012
Operating revenues from external customers	$	870,975	$	113,230		$	8,082	$	-		$	992,287
Intersegment revenues		63		(19	)		-		(44	)		-
Total revenues	$	871,038	$	113,211		$	8,082	$	(44	)	$	992,287
Net income	$	181,743	$	6,366		$	4,334	$	-		$	192,443

	Regulated		Regulated			All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas			Other		Eliminations			Total
Three Months Ended Sept. 30, 2011
Operating revenues from external customers	$	933,490	$	122,672		$	7,772	$	-		$	1,063,934
Intersegment revenues		53		(18	)		-		(35	)		-
Total revenues	$	933,543	$	122,654		$	7,772	$	(35	)	$	1,063,934
Net income (loss)	$	143,702	$	(4,219	)	$	1,235	$	-		$	140,718

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Nine Months Ended Sept. 30, 2012
Operating revenues from external customers	$	2,267,905	$	643,632	$	26,303	$	-		$	2,937,840
Intersegment revenues		198		55		-		(253	)		-
Total revenues	$	2,268,103	$	643,687	$	26,303	$	(253	)	$	2,937,840
Net income	$	331,883	$	40,205	$	9,047	$	-		$	381,135

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Nine Months Ended Sept. 30, 2011
Operating revenues from external customers	$	2,387,434	$	725,593	$	28,454	$	-		$	3,141,481
Intersegment revenues		237		201		-		(438	)		-
Total revenues	$	2,387,671	$	725,794	$	28,454	$	(438	)	$	3,141,481
Net income	$	276,218	$	27,320	$	4,828	$	-		$	308,366

11.  Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30
	2012			2011			2012			2011
(Thousands of Dollars)		Pension Benefits						Postretirement Health Care  Benefits
Service cost	$	5,679		$	4,432		$	706		$	906
Interest cost		12,776			13,059			6,131			7,097
Expected return on plan assets		(16,326	)		(16,988	)		(6,264	)		(6,990	)
Amortization of transition obligation		-			-			2,751			2,751
Amortization of prior service cost (credit)		57			56			(1,288	)		(728	)
Amortization of net loss		8,552			7,032			2,734			2,236
Net periodic benefit cost		10,738			7,591			4,770			5,272
Additional cost recognized due to the effects of regulation		-			-			972			972
Net benefit cost recognized for financial reporting	$	10,738		$	7,591		$	5,742		$	6,244

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	Nine Months Ended Sept. 30
	2012			2011			2012			2011
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care  Benefits
Service cost	$	17,039		$	13,295		$	2,119		$	2,719
Interest cost		38,329			39,176			18,395			21,293
Expected return on plan assets		(48,977	)		(50,961	)		(18,792	)		(20,971	)
Amortization of transition obligation		-			-			8,253			8,253
Amortization of prior service cost (credit)		171			167			(3,863	)		(2,185	)
Amortization of net loss		25,652			21,095			8,198			6,707
Net periodic benefit cost		32,214			22,772			14,310			15,816
Additional cost recognized due to the effects of regulation		-			-			2,918			2,918
Net benefit cost recognized for financial reporting	$	32,214		$	22,772		$	17,228		$	18,734

In January 2012, contributions of $190.5 million were made across four of Xcel Energy’s pension plans, of which $41.0 million was attributable to PSCo.  Xcel Energy does not expect additional pension contributions during 2012.

In June 2012, to manage volatility in equity pricing within the pension master trust, Xcel Energy entered into equity collar contracts with a net-zero cost at initiation on a portion of the equity securities.  The equity collar strategy is designed to reduce potential equity losses while limiting gains, resulting in lower equity volatility for the pension plans.  At Sept. 30, 2012, the mark-to-market value of these arrangements was not material to the value of the pension trust assets or PSCo’s results of operations, cash flows, or financial position.  These arrangements will expire in December 2012.

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 inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of slow down in the U.S. economy or delay in growth recovery; actions of credit rating agencies; trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; the items described under Factors Affecting Results of Operations;and the other risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2011, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2012.

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Results of Operations

PSCo’s net income was approximately $381.1 million for the nine months ended Sept. 30, 2012, compared with approximately $308.4 million for the same period in 2011.  The increase is primarily due to an electric rate increase, effective in May 2012, lower O&M expenses and the impact of warmer summer weather.  The increase was partially offset by decreased wholesale revenue due to the expiration of a long-term wholesale power sales agreement with Black Hills Corp.

Electric Revenues and Margin

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

	Nine Months Ended Sept. 30
(Millions of Dollars)	2012			2011
Electric revenues	$	2,268		$	2,387
Electric fuel and purchased power		(921	)		(1,089	)
Electric margin	$	1,347		$	1,298

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

Electric Revenues

(Millions of Dollars)	2012 vs. 2011
Fuel and purchased power cost recovery	$	(151	)
Firm wholesale (a)		(32	)
Trading, including renewable energy credit sales		(16	)
Retail rate increase		43
Estimated impact of weather		19
DSM incentive		13
DSM revenue		5
Total decrease in electric revenues	$	(119	)

(a) Decrease is primarily due to the expiration of a long-term wholesale power sales agreement with Black Hills Corp. effective Jan. 1, 2012.

Electric Margin

(Millions of Dollars)	2012 vs. 2011
Retail rate increase	$	43
Estimated impact of weather		19
DSM incentive		13
DSM revenue		5
Firm wholesale (a)		(28	)
Trading, including renewable energy credit sales		(5	)
Other, net		2
Total increase in electric margin	$	49

(a) Decrease is primarily due to the expiration of a long-term wholesale power sales agreement with Black Hills Corp. effective Jan. 1, 2012.

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Natural Gas Revenues and Margin

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

	Nine Months Ended Sept. 30
(Millions of Dollars)	2012			2011
Natural gas revenues	$	644		$	726
Cost of natural gas sold and transported		(339	)		(450	)
Natural gas margin	$	305		$	276

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

Natural Gas Revenues

(Millions of Dollars)	2012 vs. 2011
Purchased natural gas adjustment clause recovery	$	(111	)
Estimated impact of weather		(10	)
Transport sales		(3	)
DSM revenue		(1	)
Pipeline system integrity adjustment rider, offset by expense		22
Retail rate increase		13
Return on gas in storage		6
DSM incentive		1
Other, net		1
Total decrease in natural gas revenues	$	(82	)

Natural Gas Margin

(Millions of Dollars)	2012 vs. 2011
Pipeline system integrity adjustment rider, offset by expense	$	22
Retail rate increase		13
Return on gas in storage		6
DSM incentive		1
Estimated impact of weather		(10	)
Transport sales		(3	)
DSM revenue		(1	)
Other, net		1
Total increase in natural gas margin	$	29

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Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses decreased by $11.0 million, or 2.0 percent, for the nine months ended Sept. 30, 2012, compared with the same period in 2011.  The following summarizes the changes in O&M expenses:

(Millions of Dollars)	2012 vs. 2011
Lower plant generation costs		(11	)
Lower information technology costs		(5	)
Lower consulting costs		(4	)
Lower labor costs		(4	)
Lower bad debt		(3	)
Lower lease costs		(1	)
Higher employee benefit costs		13
Pipeline system integrity costs		10
Other, net (including management cost savings initiatives)		(6	)
Total decrease in operating and maintenance expenses	$	(11	)

· Lower plant generation costs are attributable to a higher level of scheduled overhaul work in 2011.

· Lower information technology costs are driven by lower vendor costs.

· Higher employee benefit costs are primarily due to higher pension expense and higher incentive costs.

· Higher pipeline system integrity costs are related to verification and testing of natural gas pipeline integrity.  These costs are recovered through a rider in Colorado.

Depreciation and Amortization —Depreciation and amortization expense increased by approximately $4.3 million, or 1.7 percent, for the nine months ended Sept. 30, 2012, compared with the same period for 2011.  The increase is due to normal system expansion.

Demand Side Management (DSM) Program Expenses — DSM program expenses increased $4.6 million, or 5.2 percent, for the nine months ended Sept. 30, 2012, compared with the same period in 2011.  The higher expense is primarily attributable to an increase in the rates used to recover program expenses.  DSM program expenses are recovered concurrently through riders and base rates.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC)— AFUDC increased by $8.5 million for the nine months ended Sept. 30, 2012, compared with the same period in 2011.  The increase is primarily due to the expansion of transmission facilities, additional construction related to the CACJA and normal system expansion.

Interest Charges —Interest charges increased by $7.3 million, or 5.3 percent, for the nine months ended Sept. 30, 2012, compared with the same period in 2011, primarily due to higher debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $8.0 million for the first nine months of 2012, compared with the same period in 2011.  The increase in income tax expense was primarily due to higher pretax earnings in 2012, partially offset by a one time tax benefit related to the restoration of a portion of the tax benefit written off in 2010 associated with federal subsidies for prescription drug plans.  As a result, PSCO recognized a discrete tax benefit of approximately $17 million.  The effective tax rate was 33.2 percent for the first nine months of 2012, compared with 37.1 percent for the same period in 2011.  The lower effective tax rate for the first nine months of 2012 was primarily due to the one time adjustment referenced above.  Without this tax benefit, the effective tax rate for the first nine months of 2012 would have been 36.2 percent.

Factors Affecting Results of Operations

Public Utility Regulation

Resource Plan — PSCo’s 2011 electric resource plan identified relatively low resource needs beginning in 2017, and proposed filling these needs with a competitive resource acquisition process.  The CPUC is expected to consider the resource plan in two phases.  In the first phase, the CPUC is expected to review planning assumptions, competitive bidding structure, and determine if PSCo should acquire generation technology.  The first phase is expected to be completed by the end of 2012 or early 2013.  In the second phase, PSCo expects to conduct the competitive acquisition process, which is expected to be submitted to the CPUC for approval in 2013.

26

In July 2012, PSCo filed two separate applications which, if approved, would update the existing resources considered in its resource plan.  The first is an application to purchase Brush Power, LLC and all of its assets including Brush generating Units 1, 3 and 4 for a total purchase price of approximately $75 million.  Located in Brush, Colo., the generating units have a total capacity of 237 MW, including Brush Unit 1, a 60 MW combined-cycle unit; Brush Unit 3, a 30 MW simple-cycle unit; and Brush Unit 4, a 147 MW combined-cycle unit.  The purchase is subject to various regulatory approvals including that of the CPUC and the FERC.  In September 2012 this application was approved by the FERC.  The Brush units currently provide energy and capacity to PSCo under purchased power agreements that are set to expire in 2017 for Brush Unit 1 and Brush Unit 3, and 2022 for Brush Unit 4.  The transaction, if approved, is expected to result in savings to wholesale and retail customers.

The second application seeks approval to retire Arapahoe Unit 4, a 109 MW coal-fired company-owned generating station at the end of 2013.  This would be an alternative to permanently fuel switching Arapahoe Unit 4 to natural gas and instead replacing the capacity and associated energy with a natural gas purchased power agreement with an existing generator.  The CPUC combined all three applications and will hold hearings in late October and early November.  A decision on all of these applications is expected in January 2013.

Renewable Energy Standard (RES) Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales be supplied by renewable energy by 2020 and includes a distributed generation standard.  PSCo has filed its 2012 and 2013 RES compliance plan.  PSCo proposed to acquire up to 30 MW of customer-sited solar projects each year and up to 6 MW of community scale solar projects.  In March 2012, the ALJ issued a recommended decision largely approving PSCo’s proposed levels of acquisition which was affirmed by the CPUC in June 2012.  PSCo has sought reconsideration of the order regarding the limit on the amounts that can be advanced to the RESA each year to cover the incremental costs of renewable energy.  The CPUC agreed with PSCo that the limitation is a soft cap.  PSCo expects to have expenditures well below the soft cap this year due to REC trading margins significantly offsetting expenses.  The CPUC also approved moving solely to a pay-for-performance basis under the Solar*Rewards distributed solar generation program, which PSCo implemented in June 2012.  The CPUC approved PSCo’s proposal to implement a solar gardens program called Solar*Rewards Community, which will allow customers who either cannot or who prefer not to install solar generation on their property to join together to build a common solar facility and receive a credit on their electric bill.

CACJA — The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of NOx from the coal-fired generation identified in the plan by at least 70 to 80 percent or greater from 2008 levels by 2017.  The plan allows PSCo to propose emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by 2017.  The total investment associated with the adopted plan is approximately $1.0 billion through 2017 and the rate impact is expected to increase future bills on average by 2 percent annually.

In September 2012, the EPA formally approved the Colorado SIP for regional haze, including the changes at the PSCo plants.

PSCo’s plan as of Sept. 30, 2012 is as follows:

· Cherokee Units 2 and 1 were shut down in 2011 and 2012, respectively, and Cherokee Unit 3 (365 MW in total) is expected to be shut down by the end of 2016, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);

· Cherokee Unit 2 was converted to a synchronous condenser to support the transmission system in 2012;

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

· Shutdown Arapahoe Unit 3 (45 MW) and Unit 4 (111 MW) in 2013;

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

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

· Install SCRs on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016.

PSCo has received certificates of public convenience and necessity (CPCN) for the conversion of Cherokee Unit 2 to a synchronous condenser, for the decommissioning of Cherokee Unit 1 and Unit 2, for the Pawnee emissions controls, for the SCRs on the Hayden units and for the new natural gas combined-cycle unit at Cherokee Station.

PSCo retired Cherokee Units 1 and 2, and is in the process of decommissioning these plants.  Separately, in July 2012, PSCo sought approval to modify the original plan to retire Arapahoe Units 3 and 4.  Subsequent transmission studies have determined that the synchronous condenser on Arapahoe Unit 3 is not needed for transmission system reliability given other upgrades to the system.  PSCo recently filed a settlement related to Arapahoe Unit 3 with the CPUC and is awaiting approval.  PSCo has also found that a purchased power agreement with an existing generator is more cost effective than operating Arapahoe Unit 4 on natural gas.  Decisions on both applications are expected in the first quarter of 2013.

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SmartGridCity™ (SGC) Cost Recovery — PSCo requested recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred to develop and operate SGC as part of its 2010 electric rate case.  In February 2011, the CPUC allowed recovery of approximately $28 million of the capital cost and all of the O&M costs.

In December 2011, PSCo requested CPUC approval for the recovery of the remaining capital investment in SGC and also provided the additional information requested.  In June 2012, the City of Boulder and the Colorado Office of Consumer Counsel filed testimony and recommended the CPUC deny PSCo’s request for recovery of the remaining portion of the SGC investment.  The ALJ is expected to recommend a decision in the fourth quarter of 2012.  Parties will have an opportunity to appeal the ALJ’s recommended decision by filing exceptions.  The CPUC will consider the recommendation from the ALJ as well as the positions of the parties before they render a decision.  If no party seeks exceptions, the ALJ’s decision will become final.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards.  State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters.  See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2011.  In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — The FERC issued Orders 1000, 1000-A, and 1000-B adopting new requirements for transmission planning, cost allocation, and development.  PSCo may be impacted by the provisions of Order 1000 that impact an incumbent’s right to build transmission because Colorado does not have legislation protecting the rights of utilities to develop transmission projects in their service areas.  PSCo submitted its compliance filing in October 2012, proposing to comply through participation in WestConnect, a consortium of utilities in the Western Interconnection.  The filing is pending FERC action.

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, 2012, 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.  PSCo has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings.  See Note 5 to the consolidated financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

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, 2011, which is incorporated herein by reference.

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Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

Item 6 —EXHIBITS

* Indicates incorporation by reference

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

3.01*	Amended and Restated Articles of Incorporation dated July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*	By-Laws dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
4.01*	Supplemental Indenture dated as of Sept. 1, 2012 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 2.25 percent First Mortgage Bonds, Series No. 23 due 2022 and $500 million principal amount of 3.60 percent First Mortgage Bonds, Series No. 24 due 2042 (Exhibit 4.01 to Form 8-K dated Sept. 11, 2012 (file no. 001-03280)).
10.01*	Amended and Restated Credit Agreement, dated as of July 27, 2012 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.03 to Xcel Energy Inc.’s Form 8-K, dated July 27, 2012 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101 †	The following materials from PSCo’s Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2012 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.

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SIGNATURES

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

		Public Service Company of Colorado
Oct. 29, 2012
	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director

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