10-Q

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 March 31, 2013

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 May 6, 2013
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	22
Item 4 —	Controls and Procedures	26
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	26
Item 1A —	Risk Factors	27
Item 4 —	Mine Safety Disclosures	27
Item 5 —	Other Information	27
Item 6 —	Exhibits	27
SIGNATURES		28
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 March 31
	2013			2012
Operating revenues
Electric	$	721,348		$	682,279
Natural gas		383,924			383,004
Steam and other		12,185			10,769
Total operating revenues		1,117,457			1,076,052
Operating expenses
Electric fuel and purchased power		319,881			310,899
Cost of natural gas sold and transported		249,620			256,877
Cost of sales — steam and other		4,805			4,167
Operating and maintenance expenses		173,041			168,382
Demand side management program expenses		33,121			29,444
Depreciation and amortization		89,550			83,589
Taxes (other than income taxes)		35,140			33,788
Total operating expenses		905,158			887,146
Operating income		212,299			188,906
Other income, net		1,577			1,032
Allowance for funds used during construction —  equity		5,923			2,726
Interest charges and financing costs
Interest charges — includes other financing costs of $1,648 and $1,790, respectively		41,388			48,291
Allowance for funds used during construction — debt		(2,151	)		(1,161	)
Total interest charges and financing costs		39,237			47,130
Income before income taxes		180,562			145,534
Income taxes		63,957			52,249
Net income	$	116,605		$	93,285

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 March 31
	2013			2012
Net income	$	116,605		$	93,285
Other comprehensive (loss) income
Derivative instruments:
Net fair value increase, net of tax of $4 and $7,972, respectively		7			13,020
Reclassification of gains to net income, net of tax of $(74) and $(230), respectively		(118	)		(375	)
		(111	)		12,645
Other comprehensive (loss) income		(111	)		12,645
Comprehensive income	$	116,494		$	105,930

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)

	Three Months Ended March 31
	2013			2012
Operating activities
Net income	$	116,605		$	93,285
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		90,809			84,948
Demand side management program amortization		1,257			1,392
Deferred income taxes		66,372			49,182
Amortization of investment tax credits		(740	)		(651	)
Allowance for equity funds used during construction		(5,923	)		(2,726	)
Net realized and unrealized hedging and derivative transactions		(164	)		6,496
Changes in operating assets and liabilities:
Accounts receivable		41,048			30,996
Accrued unbilled revenues		49,579			112,150
Inventories		42,434			56,836
Prepayments and other		(10,662	)		(3,250	)
Accounts payable		(18,383	)		(124,292	)
Net regulatory assets and liabilities		67,907			10,147
Other current liabilities		10,870			39,057
Pension and other employee benefit obligations		(44,273	)		(39,547	)
Change in other noncurrent assets		3,779			(6,434	)
Change in other noncurrent liabilities		1,720			(1,297	)
Net cash provided by operating activities		412,235			306,292
Investing activities
Utility capital/construction expenditures		(226,948	)		(152,420	)
Allowance for equity funds used during construction		5,923			2,726
Investments in utility money pool arrangement		(276,000	)		(383,000	)
Repayments from utility money pool arrangement		76,000			363,000
Net cash used in investing activities		(421,025	)		(169,694	)
Financing activities
Repayments of short-term borrowings, net		(154,000	)		-
Borrowings under utility money pool arrangement		14,000			-
Repayments under utility money pool arrangement		(14,000	)		-
Proceeds from issuance of long-term debt		493,164			-
Repayments of long-term debt		(250,000	)		-
Dividends paid to parent		(66,803	)		(134,004	)
Net cash provided by (used in) financing activities		22,361			(134,004	)
Net change in cash and cash equivalents		13,571			2,594
Cash and cash equivalents at beginning of period		5,150			3,763
Cash and cash equivalents at end of period	$	18,721		$	6,357
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(54,770	)	$	(44,384	)
Cash (paid) received for income taxes, net		(16,308	)		3,623
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	81,470		$	60,020

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	March 31, 2013			Dec. 31, 2012
Assets
Current assets
Cash and cash equivalents	$	18,721		$	5,150
Accounts receivable, net		315,019			277,461
Accounts receivable from affiliates		14,938			93,544
Investments in utility money pool arrangement		200,000			-
Accrued unbilled revenues		236,045			285,624
Inventories		181,360			223,794
Regulatory assets		146,980			143,689
Deferred income taxes		25,194			-
Derivative instruments		4,237			4,889
Prepayments and other		33,632			22,970
Total current assets		1,176,126			1,057,121
Property, plant and equipment, net		10,152,771			10,030,991
Other assets
Regulatory assets		916,822			934,728
Derivative instruments		8,908			10,868
Other		50,114			50,461
Total other assets		975,844			996,057
Total assets	$	12,304,741		$	12,084,169
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	6,477		$	256,297
Short-term debt		-			154,000
Accounts payable		332,212			359,969
Accounts payable to affiliates		26,556			30,001
Regulatory liabilities		68,331			33,723
Taxes accrued		186,670			153,614
Accrued interest		31,196			48,014
Dividends payable to parent		66,678			66,803
Derivative instruments		7,832			8,753
Other		65,952			72,669
Total current liabilities		791,904			1,183,843
Deferred credits and other liabilities
Deferred income taxes		1,878,873			1,782,828
Deferred investment tax credits		41,375			42,097
Regulatory liabilities		431,799			417,404
Asset retirement obligations		44,308			43,751
Derivative instruments		27,953			30,605
Customer advances		236,126			229,498
Pension and employee benefit obligations		280,314			324,625
Other		66,373			69,307
Total deferred credits and other liabilities		3,007,121			2,940,115
Commitments and contingencies
Capitalization
Long-term debt		3,870,164			3,374,476
Common stock – 100 shares authorized at $0.01 par value; 100 shares outstanding at March 31, 2013 and Dec. 31, 2012		-			-
Additional paid in capital		3,415,669			3,415,669
Retained earnings		1,242,865			1,192,937
Accumulated other comprehensive loss		(22,982	)		(22,871	)
Total common stockholder's equity		4,635,552			4,585,735
Total liabilities and equity	$	12,304,741		$	12,084,169

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 March 31, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2013 and 2012; and its cash flows for the three months ended March 31, 2013 and 2012.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after March 31, 2013 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, 2012 balance sheet information has been derived from the audited 2012 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2012.  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, 2012, filed with the SEC on Feb. 25, 2013.  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, 2012, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Adopted

Balance Sheet Offsetting — In December 2011, the Financial Accounting Standards Board (FASB) issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (Accounting Standards Update (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.  In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  PSCo implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 8 for the required disclosures.

Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated other comprehensive income and amounts reclassified out of accumulated other comprehensive income.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  PSCo implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 12 for the required disclosures.

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3.  Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	336,830			$	299,379
Less allowance for bad debts		(21,811	)			(21,918	)
	$	315,019			$	277,461
(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Inventories
Materials and supplies	$	55,748			$	54,486
Fuel		82,715				89,246
Natural gas		42,897				80,062
	$	181,360			$	223,794
(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	9,853,170			$	9,782,163
Natural gas plant		2,612,393				2,583,394
Common and other property		763,607				761,712
Plant to be retired (a)		141,038				152,730
Construction work in progress		616,858				506,225
Total property, plant and equipment		13,987,066				13,786,224
Less accumulated depreciation		(3,834,295	)			(3,755,233	)
	$	10,152,771			$	10,030,991

(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 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, 2012 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 June 2015.  In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011.  As of March 31, 2013, the IRS had not proposed any material adjustments to 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 March 31, 2013, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006.  In the fourth quarter of 2012, the state of Colorado commenced an examination of tax years 2006 through 2009.  As of March 31, 2013, no material adjustments had been proposed for these years.  There are currently no other 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.

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

(Millions of Dollars)	March 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	1.2	$	1.3
Unrecognized tax benefit — Temporary tax positions		8.5		8.3
Total unrecognized tax benefit	$	9.7	$	9.6

The unrecognized tax benefit amounts were 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)	March 31, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(6.2	)	$	(5.3	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $9 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.  The payables for interest related to unrecognized tax benefits at March 31, 2013 and Dec. 31, 2012 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2013 or Dec. 31, 2012.

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, 2012 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending and Recently Concluded Regulatory Proceedings — CPUC

Base Rate

Colorado 2013 Gas Rate Case —In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015.  The request is based on a 2013 forecast test year, a 10.5 percent return on equity (ROE), a rate base of $1.3 billion and an equity ratio of 56 percent.  PSCo is requesting an extension of its Pipeline System Integrity Adjustment (PSIA) rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects.  PSCo estimates that the PSIA will increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue.  In conjunction with the multi-year base rate step increases, PSCo is proposing a stay-out provision and an earnings test through the end of 2015 with a commitment to file a rate case to implement revised rates on Jan. 1, 2016.

In January 2013, the CPUC suspended the tariff filing and set the case for hearing.  In order to accommodate the procedural schedule, rates will go into effect as filed on Aug. 10, 2013, subject to refund for the difference between the filed rates and the rates approved in the final CPUC order in the case.

On April 3, 2013, four parties filed answer testimony in the natural gas case.  The CPUC Staff and Office of Consumer Counsel (OCC) recommended changes to the level of integrity management costs moved from the PSIA rider to base rates.  For clarity, PSCo will present base rate recommendations relative to deficiencies without the PSIA revenues to isolate the base rate impacts of the recommendations.  PSCo’s 2013 deficiency based on a Forecasted Test Year (FTY) net of PSIA changes was $45 million for 2013 and the revenue deficiency was $28.3 million based on a Historic Test Year (HTY).

9

The CPUC Staff recommended a rate reduction of $14.4 million, based on a HTY, an ROE of 9 percent and an equity ratio of 52 percent and other adjustments.  The OCC recommended a rate increase of $0.5 million based on a HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments.  While the OCC did not recommend that the CPUC set rates using a FTY, they did calculate a revenue deficiency of $12.4 million for 2013.  No other intervenor made ROE recommendations or specific recommendations regarding the revenue deficiency.  The major adjustments to the test year proposed by the CPUC Staff and OCC are presented below.

(Millions of Dollars)	CPUC Staff			OCC
PSCo deficiency based on a HTY	$	28.3		$	28.3
ROE and capital structure adjustments		(20.8	)		(20.0	)
Move to a 13 month average from year end rate base		(5.7	)		(3.2	)
Remove pension asset		(5.9	)		-
Remove incentive compensation		(3.5	)		(0.2	)
Challenge known and measurable		-			(9.0	)
Eliminate depreciation annualization		-			(1.8	)
Revenue adjustments		(4.1	)		(1.4	)
Resulting tax impacts		1.5			4.7
Other adjustments		(4.2	)		3.1
Recommendation	$	(14.4	)	$	0.5

On April 26, 2013, the CPUC Staff filed supplemental testimony recommending an additional net disallowance of $1.6 million for adjustments and corrections.

On April 29, 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent.  PSCo refutes the recommendations of the CPUC Staff and the OCC to disallow known and measurable adjustments and otherwise change regulatory precedent including moving from end of year rate base to average rate base for a HTY, removing the pension asset, removing incentive compensation and moving to an imputed capital structure.  PSCo agreed to recover approximately $3.5 million of revenue requirement in the PSIA, rather than through base rates and accepted the CPUC Staff’s recommendation to use deferred accounting to accommodate property tax increases.

Hearings are expected to start in May 2013 and a decision is expected in the third quarter of 2013.

Colorado 2013 Steam Rate Case —In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015.  The request is based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent.  Final rates are expected to be effective in the third quarter of 2013.

Next steps in the procedural schedule are expected to be as follows:

· Staff/Intervenor Direct Testimony – Aug. 7, 2013

· Rebuttal Testimony and Reverse Cross-Answer Testimony  – Aug. 28, 2013

· Evidentiary Hearings – Sept. 23-27, 2013

· Post-Hearing Statement Position – Oct. 11, 2013

· Proposed Findings – prior to Dec. 31, 2013

2011 Electric Rate Case Earnings Test — On April 1, 2013, PSCo filed a tariff implementing the earnings sharing mechanism compliance with the settlement and CPUC decision for PSCo’s 2011 electric rate case.  The earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year over PSCo’s authorized ROE threshold of 10 percent.  Based on the filing, PSCo’s earnings did not exceed the established threshold.  Any party disputing the calculation must file a notice with the CPUC identifying all issues by May 15, 2013.

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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 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.  For the three months ended March 31, 2013 and 2012, PSCo credited the RESA regulatory asset balance $4.0 million and $28.7 million, respectively.  The cumulative credit to the RESA regulatory asset balance was $86.8 million and $82.8 million at March 31, 2013 and Dec. 31, 2012, respectively.  The credits include the customers’ share of REC trading margins and the customers’ share of carbon offset funds.

This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and evidence regarding actual deliveries.

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, 2012, 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 that own natural gas fueled power plants for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases.  These specific purchased power agreements create a variable interest in the associated independent power producing entity.

PSCo had approximately 1,433 megawatts (MW) of capacity under long-term purchased power agreements as of March 31, 2013 and Dec. 31, 2012 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.

Environmental Contingencies

Regional Haze Rules — In 2005, the U.S. Environmental Protection Agency (EPA) finalized amendments to its regional haze rules, known as best available retrofit technology (BART), which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas.  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 emissions under BART and then set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a 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.  The CMA appealed this decision, which is now pending in the Colorado Court of Appeals.

In September 2012, the EPA granted final approval of the 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 $340.9 million.  PSCo expects the cost of any required capital investment will be recoverable from customers.

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In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10th Circuit to review the EPA’s decision approving the SIP.  WildEarth Guardians has stated that it will challenge the BART determination made for Comanche Units 1 and 2, which was a separate determination that was not part of the CACJA emission reduction plan.  In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent, or that selective catalytic reduction be added to the units.  PSCo has intervened in the case.

In 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 Clean Air Act 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.

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 is 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 when (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.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

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 and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of carbon dioxide (CO2) and other greenhouse gases contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss 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 and subsequently rejected plaintiffs’ request for rehearing.  Plaintiffs subsequently filed a petition for review with the United States Supreme Court. It is unknown whether the United States Supreme Court will grant 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 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., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants 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.  Oral arguments occurred in May 2013. It is uncertain when the Fifth Circuit will issue its decision.  Although Xcel Energy 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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Employment, Tort and Commercial Litigation

Pacific Northwest Federal Energy Regulatory Commission (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 Ninth Circuit.

In an order issued in August 2007, 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 Ninth Circuit 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 claiming refunds for the period January 2000 through June 2001.  Seattle indicated that for the period June 2000 through June 2001 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.  PSCo submitted its answering case in December 2012.

On April 5, 2013, the FERC issued an order on rehearing of its remand order issued for the October 2011 review proceedings.  The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to meet to obtain refunds.  In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear whether Seattle has a claim against PSCo prior to June 2000.

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.  First, not withstanding 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 the FERC’s standard will likely be challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty.  Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions.  If a loss were sustained, PSCo would attempt to recover those losses from other PRPs.  No accrual has been recorded for this matter.

7.  Borrowings and Other Financing Instruments

Short-Term Borrowings

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.  Money pool borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250		$	250
Amount outstandingat period end		-			-
Average amount outstanding		1			0.3
Maximum amount outstanding		12			8
Weighted average interest rate, computed on a daily basis		0.36	%		0.33	%
Weighted average interest rate at period end		N/A			N/A

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Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.  Commercial paper outstanding for PSCo was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700		$	700
Amount outstandingat period end		-			154
Average amount outstanding		154			8
Maximum amount outstanding		332			165
Weighted average interest rate, computed on a daily basis		0.34	%		0.33	%
Weighted average interest rate at period end		N/A			0.35

Letters of Credit — PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations.  At both March 31, 2013 and Dec. 31, 2012, there were $4.0 million of letters of credit outstanding.  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 March 31, 2013, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility(a)		Drawn (b)		Available
$	700.0	$	4.0	$	696.0

(a) Credit facility expires in July 2017.

(b) Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  PSCo had no direct advances on the credit facility outstanding at March 31, 2013 and Dec. 31, 2012.

Long-Term Borrowings

In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023, as well as $250 million of 3.95 percent first mortgage bonds due March 15, 2043.

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.

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.

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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.

Derivative Instruments Fair Value Measurements

PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage 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 March 31, 2013, 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, including forecasted amounts for any unsettled hedges.

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 March 31, 2013, PSCo had various vehicle fuel 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 other comprehensive income 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 months ended March 31, 2013 and 2012.

At March 31, 2013, 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.

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

The following table details the gross notional amounts of commodity forwards and options at March 31, 2013 and Dec. 31, 2012:

(Amounts in Thousands) (a)(b)	March 31, 2013		Dec. 31, 2012
Megawatt hours (MWh) of electricity		570		813
Million British thermal units (MMBtu) of natural gas		31		646
Gallons of vehicle fuel		284		307

(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.

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Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts 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.

PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.  Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.  At March 31, 2013, four of PSCo’s 10 most significant counterparties, comprising $28.6 million or 24 percent of this credit exposure at March 31, 2013, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  The remaining six significant counterparties, comprising $65.7 million or 56 percent of this credit exposure at March 31, 2013, were not rated by these agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.  All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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 March 31
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(22,871	)	$	(12,377	)
After-tax net unrealized gains related to derivatives accounted for as hedges		7			13,020
After-tax net realized gains on derivative transactions reclassified into earnings		(118	)		(375	)
Accumulated other comprehensive (loss) income related to cash flow hedges at March 31	$	(22,982	)	$	268

The following tables detail the impact of derivative activity during the three months ended March 31, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2013
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:				Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory (Assets) and Liabilities			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-	$	(180	)	(a)	$	-		$	-
Vehicle fuel and other commodity		11		-		(12	)	(d)		-			-
Total	$	11	$	-	$	(192	)		$	-		$	-
Other derivative instruments
Natural gas commodity	$	-	$	43	$	-			$	7	(c)	$	16	(b)
Total	$	-	$	43	$	-			$	7		$	16

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	Three Months Ended March 31, 2012
	Pre-Tax Fair Value							Pre-Tax (Gains) Losses
	Gains (Losses) Recognized							Reclassified into Income
	During the Period in:							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		$	20,917		$	-			$	(582	)	(a)		$	-			$	-
Vehicle fuel and other commodity			75			-				(23	)	(d)			-				-
Total		$	20,992		$	-			$	(605	)			$	-			$	-
Other derivative instruments
Natural gas commodity		$	-		$	(7,715	)		$	-				$	61,858	(c)		$	(109	)	(b)
Total		$	-		$	(7,715	)		$	-				$	61,858			$	(109	)

(a) Amounts are recorded to interest charges.

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

(c) Amounts for the three months ended March 31, 2012 included $5.0 million of settlement losses on derivatives entered 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.  Such losses for the three months ended March 31, 2013 were immaterial.  The remaining settlement losses for the three months ended March 31, 2013 and 2012 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 out of income to a regulatory asset, as appropriate.

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

PSCo had no derivative instruments designated as fair value hedges during the three months ended March 31, 2013 and 2012.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features —Contract provisions for 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 $2.4 million and $4.6 million gross liability position on the consolidated balance sheets at March 31, 2013 and Dec. 31, 2012, respectively, would have required PSCo to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $2.4 million and $4.6 million at March 31, 2013 and Dec. 31, 2012, respectively.  At March 31, 2013 and Dec. 31, 2012, 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 March 31, 2013 and Dec. 31, 2012.

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Recurring Fair Value Measurements —The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at March 31, 2013:

	March 31, 2013
	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	$	-	$	42	$	-	$	42	$	-		$	42
Other derivative instruments:
Commodity trading		-		4,746		-		4,746		(2,282	)		2,464
Natural gas commodity		-		16		-		16		-			16
Total current derivative assets	$	-	$	4,804	$	-	$	4,804	$	(2,282	)		2,522
Purchased power agreements (a)													1,715
Current derivative instruments												$	4,237
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	39	$	-	$	39	$	-		$	39
Other derivative instruments:
Commodity trading		-		1,209		-		1,209		(518	)		691
Total noncurrent derivative assets	$	-	$	1,248	$	-	$	1,248	$	(518	)		730
Purchased power agreements (a)													8,178
Noncurrent derivative instruments												$	8,908
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	-	$	4,272	$	-	$	4,272	$	(1,869	)	$	2,403
Total current derivative liabilities	$	-	$	4,272	$	-	$	4,272	$	(1,869	)		2,403
Purchased power agreements (a)													5,429
Current derivative instruments												$	7,832
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	1,128	$	-	$	1,128	$	(518	)	$	610
Total noncurrent derivative liabilities	$	-	$	1,128	$	-	$	1,128	$	(518	)		610
Purchased power agreements (a)													27,343
Noncurrent derivative instruments												$	27,953

(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) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2013 and Dec. 31, 2012.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012:

	Dec. 31, 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	$	-	$	43	$	-	$	43	$	-		$	43
Other derivative instruments:
Commodity trading		-		6,432		-		6,432		(3,301	)		3,131
Natural gas commodity		-		7		-		7		(7	)		-
Total current derivative assets	$	-	$	6,482	$	-	$	6,482	$	(3,308	)		3,174
Purchased power agreements (a)													1,715
Current derivative instruments												$	4,889
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	39	$	-	$	39	$	-		$	39
Other derivative instruments:
Commodity trading		-		3,768		-		3,768		(1,546	)		2,222
Total noncurrent derivative assets	$	-	$	3,807	$	-	$	3,807	$	(1,546	)		2,261
Purchased power agreements (a)													8,607
Noncurrent derivative instruments												$	10,868
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	5,958	$	-	$	5,958	$	(2,712	)	$	3,246
Natural gas commodity		-		85		-		85		(7	)		78
Total current derivative liabilities	$	-	$	6,043	$	-	$	6,043	$	(2,719	)		3,324
Purchased power agreements (a)													5,429
Current derivative instruments												$	8,753
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	3,450	$	-	$	3,450	$	(1,546	)	$	1,904
Total noncurrent derivative liabilities	$	-	$	3,450	$	-	$	3,450	$	(1,546	)		1,904
Purchased power agreements (a)													28,701
Noncurrent derivative instruments												$	30,605

(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) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2013 and Dec. 31, 2012.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were no changes in Level 3 recurring fair value measurements for the three months ended March 31, 2013 and 2012.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for the three months ended March 31, 2013 and 2012.

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Fair Value of Long-Term Debt

As of March 31, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2013				Dec. 31, 2012
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,876,641	$	4,323,766	$	3,630,773	$	4,131,866

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 March 31, 2013 and Dec. 31, 2012, 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, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2013			2012
Interest income	$	914		$	1,028
Other nonoperating income		882			568
Insurance policy expense		(219	)		(564	)
Other income, net	$	1,577		$	1,032

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 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.

20

	Regulated		Regulated			All			Reconciling				Consolidated
(Thousands of Dollars)	Electric			Natural Gas			Other			Eliminations				Total
Three Months Ended March 31, 2013
Operating revenues from external customers	$	721,348		$	383,924		$	12,185		$	-			$	1,117,457
Intersegment revenues		88			47			-			(135	)			-
Total revenues	$	721,436		$	383,971		$	12,185		$	(135	)		$	1,117,457
Net income	$	78,468		$	33,799		$	4,338		$	-			$	116,605
	Regulated		Regulated			All			Reconciling				Consolidated
(Thousands of Dollars)	Electric			Natural Gas			Other			Eliminations				Total
Three Months Ended March 31, 2012
Operating revenues from external customers	$	682,279		$	383,004		$	10,769		$	-			$	1,076,052
Intersegment revenues		92			55			-			(147	)			-
Total revenues	$	682,371		$	383,059		$	10,769		$	(147	)		$	1,076,052
Net income	$	61,333		$	28,310		$	3,642		$	-			$	93,285

11.  Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	2013			2012			2013			2012
(Thousands of Dollars)		Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,302		$	5,497		$	803		$	823
Interest cost		11,540			12,624			5,934			6,142
Expected return on plan assets		(15,955	)		(16,235	)		(7,307	)		(6,270	)
Amortization of transition obligation		-			-			196			2,751
Amortization of prior service (credit) cost		(266	)		57			(1,229	)		(1,288	)
Amortization of net loss		10,854			8,305			3,490			2,604
Net periodic benefit cost		12,475			10,248			1,887			4,762
Additional cost recognized due to the effects of regulation		-			-			-			973
Net benefit cost recognized for financial reporting	$	12,475		$	10,248		$	1,887		$	5,735

In January 2013, contributions of $191.5 million were made across four of Xcel Energy’s pension plans, of which $44.3 million was attributable to PSCo.  Xcel Energy does not expect additional pension contributions during 2013.

12.  Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(22,871	)
Other comprehensive income before reclassifications		7
Gains reclassified from net accumulated other comprehensive loss		(118	)
Net current period other comprehensive loss		(111	)
Accumulated other comprehensive loss at March 31	$	(22,982	)

21

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2013 were as follows:

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
Gains on cash flow hedges:
Interest rate derivatives	$	(180	) (a)
Vehicle fuel derivatives		(12	) (b)
Total, pre-tax		(192	)
Tax expense		74
Total amounts reclassified, net of tax	$	(118	)

(a) Included in interest charges.

(b) Included in O&M expenses.

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, 2012, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended March 31, 2013.

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Results of Operations

PSCo’s net income was approximately $116.6 million for the three months ended March 31, 2013, compared with approximately $93.3 million for the same period in 2012.  The increase is mainly due to the electric rate increases in May 2012 and January 2013, cooler weather impacting electric and gas margins and lower interest charges.  The increase is partially offset by higher depreciation expense and O&M expenses.

Electric Revenues and Margin

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

	Three Months Ended March 31
(Millions of Dollars)	2013			2012
Electric revenues	$	721			$	682
Electric fuel and purchased power		(320	)			(311	)
Electric margin	$	401			$	371

The following tables summarize the components of the changes in electric revenues and electric margin for the three months ended March 31:

Electric Revenues

(Millions of Dollars)	2013 vs. 2012
Retail rate increases	$	19
Fuel and purchased power cost recovery		11
Estimated impact of weather		4
Demand side management (DSM) program revenue		3
Non-fuel riders		3
Trading, including renewable energy credit sales		(3	)
Other, net		2
Total increase in electric revenues	$	39

Electric Margin

(Millions of Dollars)	2013 vs. 2012
Retail rate increases	$	19
Estimated impact of weather		4
DSM program revenue		3
Non-fuel riders		3
Other, net		1
Total increase in electric margin	$	30

Natural Gas Revenues and Margin

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

	Three Months Ended March 31
(Millions of Dollars)	2013			2012
Natural gas revenues	$	384			$	383
Cost of natural gas sold and transported		(250	)			(257	)
Natural gas margin	$	134			$	126

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The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the three months ended March 31:

Natural Gas Revenues

(Millions of Dollars)	2013 vs. 2012
Estimated impact of weather	$	9
Purchased natural gas adjustment clause recovery		(7	)
Other, net		(1	)
Total increase in natural gas revenues	$	1

Natural Gas Margin

(Millions of Dollars)	2013 vs. 2012
Estimated impact of weather	$	9
Other, net		(1	)
Total increase in natural gas margin	$	8

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased by $4.7 million, or 2.8 percent, for the first quarter of 2013 compared with the same period in 2012.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2013 vs. 2012
Vegetation management costs	$	3
Plant generation costs		3
Employee benefit costs		2
Information technology costs		(3	)
Total increase in O&M expenses	$	5

DSM Program Expenses — DSM program expenses increased $3.7 million, or 12.5 percent, for the first quarter of 2013 compared with the same period in 2012.  The higher expense is primarily attributable to an increase in the electric rate used to recover program expenses.  DSM program expenses are recovered concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $6.0 million, or 7.1 percent, for the first quarter of 2013 compared with the same period for 2012.  The increase is due to normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by $1.4 million, or 4.0 percent, for the first quarter of 2013 compared with the same period in 2012.  The increase is due to the amortization of previously deferred electric property taxes.  Increased property taxes in Colorado related to the electric retail business are being deferred based on the multi-year rate settlement approved by the CPUC in May 2012.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC)— AFUDC increased by $4.2 million for the first quarter of 2013 compared with the same period in 2012.  The increase is due to construction related to the CACJA, the expansion of transmission facilities and other capital investments.

Interest Charges —Interest charges decreased by $6.9 million, or 14.3 percent, for the first quarter of 2013 compared with the same period in 2012.  The decrease is due to lower interest rates, primarily related to refinancings completed in the second half of 2012, partially offset by higher long-term debt levels to fund investments in utility operations.

Income Taxes — Income tax expense increased $11.7 million for the first quarter of 2013 compared with the same period in 2012.  The increase in income tax expense was primarily due to higher pretax earnings in 2013.  The ETR was 35.4 percent for the first quarter of 2013 compared with 35.9 percent for the same period in 2012.

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Factors Affecting Results of Operations

Public Utility Regulation

2011 Electric Resource Plan (ERP) — In July 2012, PSCo filed two separate applications to update its resource plan.  The first was 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.  The Brush units currently provide 237 MW of natural gas fueled capacity and energy to PSCo under purchased power agreements (PPAs) that are set to expire in 2017 for Brush Unit 1 and Brush Unit 3, and 2022 for Brush Unit 4.

The second application sought approval to retire Arapahoe Unit 4, a 109 MW coal-fired company-owned generating station at the end of 2013.  This was presented as an alternative to permanently fuel switching Arapahoe Unit 4 to natural gas and instead replacing the capacity and associated energy with a natural gas PPA with an existing generator.

In January 2013, the CPUC denied approval of the acquisition due to the risks associated with the transaction.  In February 2013, the transaction was terminated.  The CPUC also decided that it was best not to make the decision to retire Arapahoe Unit 4 in this first phase of the resource plan and instead determined that the decision is best made after the retirement can be compared to bids received in the second phase.

2013 All-Source Solicitation — In January 2013, the CPUC approved with modifications the 2011 ERP.  In March 2013, PSCo issued an All-Source RFP for 250 MW by the end of 2018.  Proposals for the All-Source RFP may be for purchase power agreements, self-build or contracts with a build-ownership transfer option.  PSCo also issued a separate wind RFP for purchase power agreements only.  Bid proposals in response to the Wind RFP were received in April 2013.

Next steps in the 2013 All-Source solicitation schedule are expected to be as follows:

· The deadline for All-Source generation bids – May 2013

· Delivery of the wind evaluation assessment report to CPUC – May 2013

· Delivery of the All-Source evaluation assessment report to CPUC – September 2013

· CPUC evaluation and regulatory approval of wind-based generation proposals – October 2013

· CPUC evaluation and regulatory approval of All-Source generation proposals – December 2013

San Luis Valley-Calumet-Comanche Transmission Project — In May 2009, PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a 230 kilovolt and 345 kilovolt line and substation construction project.  The line was intended to assist in bringing solar power in the San Luis Valley to customers.  In March 2011, the CPUC granted a CPCN for this project.  The CPUC’s decisions have been appealed to the Costilla County District Court by Blanca Ranch Holdings, LLC and Trinchera Ranch Holdings, LLC, and are pending before the Court.

PSCo has determined that due to lower projected load growth, lower gas prices and the higher cost of solar thermal generation, the proposed transmission project would not be necessary for the foreseeable future.  On April 30, 2013, PSCo provided notice to the CPUC that the transmission project should not be built.

Boulder, Colo. Franchise Agreement — In November 2011, two ballot measures were passed by the citizens of Boulder.  The first measure increased the occupation tax to raise an additional $1.9 million annually for funding the exploration costs of forming a municipal utility and acquiring the PSCo electric distribution system in Boulder.  The second measure authorized the formation and operation of a municipal light and power utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage.

In December 2012, Boulder issued a white paper exploring opportunities for reaching its energy goals with PSCo, in lieu of condemnation.  PSCo has advised Boulder that it is willing to discuss many of these opportunities.  In February 2013, Boulder staff published a memorandum on the feasibility of creating a municipal utility.  In April 2013, the Boulder City Council voted to proceed with the possible formation of a municipal electric utility, including considering authorization to commence legal actions needed to determine any potential rights or obligations of Boulder and means of separating from Xcel Energy’s system under state and federal law.  Boulder City Council is not expected to make a final decision regarding a condemnation action until August 2013.

Should Boulder attempt to condemn PSCo facilities, PSCo would seek to obtain full compensation for the property and business taken by Boulder and for all damages resulting to PSCo and its system.  PSCo would also seek appropriate compensation for stranded costs with the FERC.

25

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, 2012.  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 Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively.  In Order 1000, the FERC required utilities to develop tariffs that provide for joint transmission planning and cost allocation for all FERC-jurisdictional utilities within a region.  In addition, FERC Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation.  A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal Right of First Refusal (ROFR) to build certain types of transmission projects in its service area.  The FERC required that opportunity to build such projects would extend to competitive transmission developers.  PSCo is not in an RTO and therefore is responsible for making its own Order 1000 compliance filing.  PSCo has made its initial compliance filing to incorporate new provisions into its tariffs regarding regional planning and cost allocation; the filings to address interregional planning and cost allocation requirements are due July 10, 2013.

Colorado does not have legislation protecting ROFR rights for incumbent utilities.  PSCo submitted its compliance filing to address the regional planning and cost allocation requirements of Order 1000, proposing that the region that PSCo would join was WestConnect, a consortium of utilities in the Western Interconnection.  In March 2013, the FERC issued its initial order on PSCo’s compliance filing and required a number of changes, including the requirement that cost allocation for new projects identified through the planning process be binding upon all participants in the planning process.  This requirement poses a challenge because WestConnect is compromised of a number of utilities that are not subject to FERC jurisdiction and are unwilling to participate in a regional planning or cost allocation process if they do not have the ultimate authority to decline to help fund a project identified through the regional process.  PSCo and other WestConnect members are required to file additional compliance language by July 2013.  In addition, on April 22, 2013, PSCo and other WestConnect members requested rehearing on various aspects of the March 2013 order, including the requirement that cost allocation be binding.

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 March 31, 2013, 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.

26

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, 2012, which is incorporated herein by reference.

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 March 1, 2013 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.50 percent First Mortgage Bonds, Series No. 25 due 2023 and $250 million principal amount of 3.95 percent First Mortgage Bonds, Series No. 26 due 2043 (Exhibit 4.01 to Form 8-K dated March 26, 2013 (file no. 001-03280)).
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 March 31, 2013 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.

27

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
May 6, 2013
	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

28

EX-31.01

Exhibit 31.01

CERTIFICATION

I, David L. Eves, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Colorado;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 6, 2013

/s/ DAVID L. EVES

David L. Eves

President, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Colorado;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 6, 2013

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Public Service Company of Colorado (PSCo) on Form 10-Q for the quarter ended March 31, 2013, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of PSCo certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1)  The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)  The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of PSCo as of the dates and for the periods expressed in the Form 10-Q.

Date:  May 6, 2013

/s/ DAVID L. EVES

David L. Eves

President, Chief Executive Officer and Director

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to PSCo and will be retained by PSCo and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

Public Service Company of Colorado Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Forward-looking statements are made in written documents and oral presentations of PSCo.  These statements are based on management’s beliefs as well as assumptions and information currently available to management. 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. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause PSCo’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

· Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

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

· Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where PSCo has a financial interest;

· Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

· Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

· Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, PSCo, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

· Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

· Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;

· Increased competition in the utility industry or additional competition in the markets served by PSCo, Xcel Energy Inc. or any of its other subsidiaries;

· State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

· Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of   compliance;

· Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

· Social attitudes regarding the utility and power industries;

· Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

· Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

· Risks associated with implementations of new technologies; and

· Other business or investment considerations that may be disclosed from time to time in PSCo’s SEC filings, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2012, or in other publicly disseminated written documents.

PSCo undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

1

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Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	Mar. 31, 2013		Dec. 31, 2012
Credit Facility [Abstract]
Credit facility	$ 700,000,000	[1]
Drawn	4,000,000	[2]
Available	696,000,000
Credit facility bank borrowings outstanding	$ 0		$ 0

[1] Credit facility expires in July 2017.

[2] Includes outstanding letters of credit.

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Other Income, Net (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Other Income, Net [Abstract]
Interest income	$ 914	$ 1,028
Other nonoperating income	882	568
Insurance policy expense	(219)	(564)
Other income, net	$ 1,577	$ 1,032

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Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Derivatives, Net [Member], USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Commodity Derivatives, Net [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Transfers into Level 3	$ 0	$ 0
Transfers out of Level 3	$ 0	$ 0

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Rate Matters (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended		1 Months Ended	0 Months Ended	1 Months Ended	0 Months Ended	1 Months Ended	0 Months Ended	1 Months Ended			0 Months Ended				1 Months Ended				3 Months Ended	1 Months Ended	3 Months Ended			1 Months Ended				0 Months Ended
	Apr. 29, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case [Member]	Apr. 03, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case [Member] Counterparty	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case [Member]	Apr. 29, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, 2013 Rates [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, 2013 Rates [Member]	Apr. 29, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, 2014 Rates [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, 2014 Rates [Member]	Apr. 29, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, 2015 Rates [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, 2015 Rates [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, 2014 Pipeline System Integrity Adjustment [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, 2015 Pipeline System Integrity Adjustment [Member]	Apr. 03, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, Net of PSIA Changes, Based on Forecasted Test Year [Member]	Apr. 26, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, Net of PSIA Changes, Based on Historical Test Year [Member]	Apr. 03, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, Net of PSIA Changes, Based on Historical Test Year [Member]	Apr. 29, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2013 Gas Rate Case, Pipeline System Integrity Adjustment [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Steam Rate Case [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Steam Rate Case, 2013 Steam Rates [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Steam Rate Case, 2014 Steam Rates [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] 2013 Steam Rate Case, 2015 Steam Rates [Member]	Mar. 31, 2013 Colorado Public Utilities Commission (CPUC) [Member] 2011 Electric Rate Case [Member]	Mar. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] Renewable Energy Credit (REC) Sharing [Member]	Mar. 31, 2013 Colorado Public Utilities Commission (CPUC) [Member] Renewable Energy Credit (REC) Sharing [Member]	Mar. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] Renewable Energy Credit (REC) Sharing [Member]	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] Renewable Energy Credit (REC) Sharing [Member]	Mar. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] Renewable Energy Credit (REC) Sharing [Member] Shareholders [Member]	May 31, 2011 Colorado Public Utilities Commission (CPUC) [Member] Renewable Energy Credit (REC) Sharing [Member] Shareholders [Member]	Mar. 31, 2012 Colorado Public Utilities Commission (CPUC) [Member] Renewable Energy Credit (REC) Sharing [Member] Customers [Member]	May 31, 2011 Colorado Public Utilities Commission (CPUC) [Member] Renewable Energy Credit (REC) Sharing [Member] Customers [Member]	Apr. 03, 2013 Office of Consumer Counsel [Member] 2013 Gas Rate Case, Net of PSIA Changes, Based on Forecasted Test Year [Member]	Apr. 03, 2013 Office of Consumer Counsel [Member] 2013 Gas Rate Case, Net of PSIA Changes, Based on Historical Test Year [Member]
Rate Matters [Abstract]
Entity's requested rate increase (decrease)					$ 48.5		$ 9.9		$ 12.1	$ 26.8	$ 24.7	$ 45.0		$ 28.3	$ 3.5		$ 1.6	$ 0.9	$ 2.3											$ 28.3
Entity's requested return on equity (in hundredths)	10.30%		10.50%													10.50%
Entity's rate base in requested rate increase (decrease)			1,300													21
Entity's requested equity ratio percent (in hundredths)			56.00%													56.00%
Number of intervenors filing testimony		4
Return on equity recommended by third parties (in hundredths)														9.00%																9.00%
Equity ratio percent recommended by third parties (in hundredths)														52.00%																51.03%
ROE and capital structure adjustments														(20.8)																(20.0)
Move to a 13 month average from year end rate base														(5.7)																(3.2)
Remove pension asset														(5.9)																0
Remove incentive compensation														(3.5)																(0.2)
Challenge known and measurable														0																(9.0)
Eliminate depreciation annualization														0																(1.8)
Revenue adjustments														(4.1)																(1.4)
Resulting tax impacts														1.5																4.7
Other adjustments														(4.2)																3.1
Recommendation														(14.4)															12.4	0.5
Recommended net disallowance for adjustments and corrections													(1.6)
Entity's revised requested rate increase (decrease)				44.8		9.0		10.9
Return on equity used in weather normalized earnings test (in hundredths)																				10.00%
Initial percentage of margin associated with entity's stand-alone REC transactions (in hundredths)																										20.00%		80.00%
Ultimate percentage of margin associated with entity's stand-alone REC transactions (in hundredths)																										10.00%		90.00%
Entity's margin threshold determining the percentage of margin sharing																					20
Percentage of entity's margin on hybrid RECs approved for first $20 million of margins (in hundredths)																									20.00%		80.00%
Percentage of entity's margin on hybrid RECs approved for margins in excess of $20 million (in hundredths)																									10.00%		90.00%
Customers' share of margins credited against entity's RESA regulatory asset balance																						4.0	28.7
Cumulative credit against entity's RESA regulatory asset balance																						$ 86.8		$ 82.8

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Borrowings and Other Financing Instruments (Tables)

3 Months Ended

Mar. 31, 2013

Borrowings and Other Financing Instruments [Abstract]

Committed Credit Facility Available

At March 31, 2013, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility(a)		Drawn (b)		Available
$	700.0	$	4.0	$	696.0

(a) Credit facility expires in July 2017.

(b) Includes outstanding letters of credit.

Money Pool [Member]

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

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. Money pool borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250		$	250
Amount outstandingat period end		-			-
Average amount outstanding		1			0.3
Maximum amount outstanding		12			8
Weighted average interest rate, computed on a daily basis		0.36	%		0.33	%
Weighted average interest rate at period end		N/A			N/A

Commercial Paper [Member]

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for PSCo was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700		$	700
Amount outstandingat period end		-			154
Average amount outstanding		154			8
Maximum amount outstanding		332			165
Weighted average interest rate, computed on a daily basis		0.34	%		0.33	%
Weighted average interest rate at period end		N/A			0.35

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Benefit Plans and Other Postretirement Benefits (Details) (USD $)	1 Months Ended	3 Months Ended
	Jan. 31, 2013	Mar. 31, 2013	Mar. 31, 2012
Pension Benefits [Member]
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 6,302,000	$ 5,497,000
Interest cost		11,540,000	12,624,000
Expected return on plan assets		(15,955,000)	(16,235,000)
Amortization of transition obligation		0	0
Amortization of prior service (credit) cost		(266,000)	57,000
Amortization of net loss		10,854,000	8,305,000
Net periodic benefit cost		12,475,000	10,248,000
Additional cost recognized due to the effects of regulation		0	0
Net benefit cost recognized for financial reporting		12,475,000	10,248,000
Total contributions to Xcel Energy's pension plans during the period	44,300,000
Postretirement Health Care Benefits [Member]
Components of Net Periodic Benefit Cost [Abstract]
Service cost		803,000	823,000
Interest cost		5,934,000	6,142,000
Expected return on plan assets		(7,307,000)	(6,270,000)
Amortization of transition obligation		196,000	2,751,000
Amortization of prior service (credit) cost		(1,229,000)	(1,288,000)
Amortization of net loss		3,490,000	2,604,000
Net periodic benefit cost		1,887,000	4,762,000
Additional cost recognized due to the effects of regulation		0	973,000
Net benefit cost recognized for financial reporting		1,887,000	5,735,000
Xcel Energy Inc. [Member] | Pension Benefits [Member]
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to Xcel Energy's pension plans during the period	$ 191,500,000
Number of Xcel Energy's pension plans to which contributions were made	4

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Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at beginning of period	$ (22,871)	$ (12,377)
After-tax net unrealized gains related to derivatives accounted for as hedges	7	13,020
After-tax net realized gains on derivative transactions reclassified into earnings	(118)	(375)
Accumulated other comprehensive loss related to cash flow hedges at end of period	$ (22,982)	$ 268

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2013		Dec. 31, 2012
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0		$ 154,000,000
Commercial Paper [Member]
Short-term Debt [Line Items]
Borrowing limit	700,000,000		700,000,000
Amount outstanding at period end	0		154,000,000
Average amount outstanding	154,000,000		8,000,000
Maximum amount outstanding	332,000,000		165,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.34%		0.33%
Weighted average interest rate at end of period (in hundredths)		[1]	0.35%
Money Pool [Member]
Short-term Debt [Line Items]
Borrowing limit	250,000,000		250,000,000
Amount outstanding at period end	0		0
Average amount outstanding	1,000,000		300,000
Maximum amount outstanding	$ 12,000,000		$ 8,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.36%		0.33%
Weighted average interest rate at end of period (in hundredths)		[1]		[1]

[1] N/A

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Carrying Amount [Member]
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 3,876,641	$ 3,630,773
Fair Value [Member]
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,323,766	$ 4,131,866

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Management's Opinion

3 Months Ended

Mar. 31, 2013

Management's Opinion [Abstract]

Management's Opinion

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 March 31, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2013 and 2012; and its cash flows for the three months ended March 31, 2013 and 2012. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2013 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, 2012 balance sheet information has been derived from the audited 2012 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2012. 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, 2012, filed with the SEC on Feb. 25, 2013. 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.

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0		$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0		0
Cash Flow Hedges [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	11,000		20,992,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(192,000)		(605,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0
Pre-tax gains (losses) recognized during the period in income	0		0
Cash Flow Hedges [Member] | Interest Rate [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		20,917,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(180,000)	[1]	(582,000)	[1]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0
Pre-tax gains (losses) recognized during the period in income	0		0
Cash Flow Hedges [Member] | Vehicle Fuel And Other Commodity [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	11,000		75,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(12,000)	[2]	(23,000)	[2]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0
Pre-tax gains (losses) recognized during the period in income	0		0
Other Derivative Instruments [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	43,000		(7,715,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	7,000		61,858,000
Pre-tax gains (losses) recognized during the period in income	16,000		(109,000)
Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)			5,000,000
Other Derivative Instruments [Member] | Natural Gas Commodity for Electric Generation [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	43,000		(7,715,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	7,000	[3]	61,858,000	[3]
Pre-tax gains (losses) recognized during the period in income	$ 16,000	[4]	$ (109,000)	[4]

[1] Amounts are recorded to interest charges.

[2] Amounts are recorded to operating and maintenance (O&M) expenses.

[3] Amounts for the three months ended March 31, 2012 included $5.0 million of settlement losses 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. Such losses for the three months ended March 31, 2013 were immaterial. The remaining settlement losses for the three months ended March 31, 2013 and 2012 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.

[4] Amounts are recorded to electric fuel and purchased power.

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Benefit Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2013

Benefit Plans and Other Postretirement Benefits [Abstract]

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	2013			2012			2013			2012
(Thousands of Dollars)		Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,302		$	5,497		$	803		$	823
Interest cost		11,540			12,624			5,934			6,142
Expected return on plan assets		(15,955	)		(16,235	)		(7,307	)		(6,270	)
Amortization of transition obligation		-			-			196			2,751
Amortization of prior service (credit) cost		(266	)		57			(1,229	)		(1,288	)
Amortization of net loss		10,854			8,305			3,490			2,604
Net periodic benefit cost		12,475			10,248			1,887			4,762
Additional cost recognized due to the effects of regulation		-			-			-			973
Net benefit cost recognized for financial reporting	$	12,475		$	10,248		$	1,887		$	5,735

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

Segment Information [Abstract]

Results from Continuing Operations by Reportable Segment

	Regulated		Regulated			All			Reconciling				Consolidated
(Thousands of Dollars)	Electric			Natural Gas			Other			Eliminations				Total
Three Months Ended March 31, 2013
Operating revenues from external customers	$	721,348		$	383,924		$	12,185		$	-			$	1,117,457
Intersegment revenues		88			47			-			(135	)			-
Total revenues	$	721,436		$	383,971		$	12,185		$	(135	)		$	1,117,457
Net income	$	78,468		$	33,799		$	4,338		$	-			$	116,605

	Regulated		Regulated			All			Reconciling				Consolidated
(Thousands of Dollars)	Electric			Natural Gas			Other			Eliminations				Total
Three Months Ended March 31, 2012
Operating revenues from external customers	$	682,279		$	383,004		$	10,769		$	-			$	1,076,052
Intersegment revenues		92			55			-			(147	)			-
Total revenues	$	682,371		$	383,059		$	10,769		$	(147	)		$	1,076,052
Net income	$	61,333		$	28,310		$	3,642		$	-			$	93,285

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Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Credit Related Contingent Features [Abstract]
Derivative instruments in a gross liability position	$ 2,400,000	$ 4,600,000
Payments required if credit ratings were downgraded below investment grade	2,400,000	4,600,000
Collateral posted on derivative instruments	0	0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2013

Other Comprehensive Income [Abstract]

Changes in Accumulated Other Comprehensive Loss, Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(22,871	)
Other comprehensive income before reclassifications		7
Gains reclassified from net accumulated other comprehensive loss		(118	)
Net current period other comprehensive loss		(111	)
Accumulated other comprehensive loss at March 31	$	(22,982	)

Reclassification out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2013 were as follows:

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
Gains on cash flow hedges:
Interest rate derivatives	$	(180	) (a)
Vehicle fuel derivatives		(12	) (b)
Total, pre-tax		(192	)
Tax expense		74
Total amounts reclassified, net of tax	$	(118	)

(a) Included in interest charges.

(b) Included in O&M expenses.

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Selected Balance Sheet Data (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Accounts receivable, net [Abstract]
Accounts receivable	$ 336,830		$ 299,379
Less allowance for bad debts	(21,811)		(21,918)
Accounts receivable, net	315,019		277,461
Inventories [Abstract]
Inventories	181,360		223,794
Property, plant and equipment, net [Abstract]
Property, plant and equipment	13,987,066		13,786,224
Less accumulated depreciation	(3,834,295)		(3,755,233)
Property, plant and equipment, net	10,152,771		10,030,991
Electric Plant [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	9,853,170		9,782,163
Natural Gas Plant [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	2,612,393		2,583,394
Common and Other Property [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	763,607		761,712
Plant to be Retired [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	141,038	[1]	152,730	[1]
Construction Work in Progress [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	616,858		506,225
Materials and Supplies [Member]
Inventories [Abstract]
Inventories	55,748		54,486
Fuel [Member]
Inventories [Abstract]
Inventories	82,715		89,246
Natural Gas [Member]
Inventories [Abstract]
Inventories	$ 42,897		$ 80,062

[1] 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 2012, Cherokee Unit 1 was retired. Amounts are presented net of accumulated depreciation.

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	100	100
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	100	100

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Income Taxes (Details) (USD $)			3 Months Ended		3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012 Internal Revenue Service (IRS) [Member]	Mar. 31, 2013 Internal Revenue Service (IRS) [Member]	Dec. 31, 2012 State Jurisdiction [Member]	Mar. 31, 2013 State Jurisdiction [Member]
Tax Audits [Abstract]
Year(s) no longer subject to audit as statute of limitations has expired				2008
Earliest year subject to examination				2009		2006
Year(s) under examination			2010 and 2011		2006 through 2009
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit - Permanent tax positions	$ 1,200,000	$ 1,300,000
Unrecognized tax benefit - Temporary tax positions	8,500,000	8,300,000
Total unrecognized tax benefit	9,700,000	9,600,000
NOL and tax credit carryforwards	(6,200,000)	(5,300,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	(9,000,000)
Amounts accrued for penalties related to unrecognized tax benefits	$ 0	$ 0

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Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) (First Mortgage Bonds [Member], USD $) In Millions, unless otherwise specified	1 Months Ended
	Mar. 31, 2013
Series Due March 15, 2023 [Member]
Long-Term Borrowings [Abstract]
Face amount	$ 250
Interest rate, stated percentage (in hundredths)	2.50%
Maturity date	Mar. 15, 2023
Series Due March 15, 2043 [Member]
Long-Term Borrowings [Abstract]
Face amount	$ 250
Interest rate, stated percentage (in hundredths)	3.95%
Maturity date	Mar. 15, 2043

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating revenues
Electric	$ 721,348	$ 682,279
Natural gas	383,924	383,004
Steam and other	12,185	10,769
Total operating revenues	1,117,457	1,076,052
Operating expenses
Electric fuel and purchased power	319,881	310,899
Cost of natural gas sold and transported	249,620	256,877
Cost of sales - steam and other	4,805	4,167
Operating and maintenance expenses	173,041	168,382
Demand side management program expenses	33,121	29,444
Depreciation and amortization	89,550	83,589
Taxes (other than income taxes)	35,140	33,788
Total operating expenses	905,158	887,146
Operating income	212,299	188,906
Other income, net	1,577	1,032
Allowance for funds used during construction - equity	5,923	2,726
Interest charges and financing costs
Interest charges - includes other financing costs of $1,648 and $1,790, respectively	41,388	48,291
Allowance for funds used during construction - debt	(2,151)	(1,161)
Total interest charges and financing costs	39,237	47,130
Income before income taxes	180,562	145,534
Income taxes	63,957	52,249
Net income	$ 116,605	$ 93,285

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Other derivative instruments [Abstract]
Current derivative instruments	$ 4,237		$ 4,889
Other derivative instruments [Abstract]
Noncurrent derivative instruments	8,908		10,868
Other derivative instruments [Abstract]
Current derivative instruments	7,832		8,753
Other derivative instruments [Abstract]
Noncurrent derivative instruments	27,953		30,605
Fair Value Measured on a Recurring Basis [Member]
Derivatives Designated as Cash Flow Hedges [Abstract]
Vehicle fuel and other commodity	42		43
Other derivative instruments [Abstract]
Commodity trading	2,464		3,131
Natural gas commodity	16		0
Total current derivative assets	2,522		3,174
Purchased power agreements	1,715	[1]	1,715	[1]
Current derivative instruments	4,237		4,889
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	39		39
Other derivative instruments [Abstract]
Commodity trading	691		2,222
Total noncurrent derivative assets	730		2,261
Purchased power agreements	8,178	[1]	8,607	[1]
Noncurrent derivative instruments	8,908		10,868
Other derivative instruments [Abstract]
Commodity trading	2,403		3,246
Natural gas commodity			78
Total current derivative liabilities	2,403		3,324
Purchased power agreements	5,429	[1]	5,429	[1]
Current derivative instruments	7,832		8,753
Other derivative instruments [Abstract]
Commodity trading	610		1,904
Total noncurrent derivative liabilities	610		1,904
Purchased power agreements	27,343	[1]	28,701	[1]
Noncurrent derivative instruments	27,953		30,605
Fair Value Measured on a Recurring Basis [Member] | Level 1 [Member]
Derivatives Designated as Cash Flow Hedges [Abstract]
Vehicle fuel and other commodity	0		0
Other derivative instruments [Abstract]
Commodity trading	0		0
Natural gas commodity	0		0
Total current derivative assets	0		0
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0		0
Other derivative instruments [Abstract]
Commodity trading	0		0
Total noncurrent derivative assets	0		0
Other derivative instruments [Abstract]
Commodity trading	0		0
Natural gas commodity			0
Total current derivative liabilities	0		0
Other derivative instruments [Abstract]
Commodity trading	0		0
Total noncurrent derivative liabilities	0		0
Fair Value Measured on a Recurring Basis [Member] | Level 2 [Member]
Derivatives Designated as Cash Flow Hedges [Abstract]
Vehicle fuel and other commodity	42		43
Other derivative instruments [Abstract]
Commodity trading	4,746		6,432
Natural gas commodity	16		7
Total current derivative assets	4,804		6,482
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	39		39
Other derivative instruments [Abstract]
Commodity trading	1,209		3,768
Total noncurrent derivative assets	1,248		3,807
Other derivative instruments [Abstract]
Commodity trading	4,272		5,958
Natural gas commodity			85
Total current derivative liabilities	4,272		6,043
Other derivative instruments [Abstract]
Commodity trading	1,128		3,450
Total noncurrent derivative liabilities	1,128		3,450
Fair Value Measured on a Recurring Basis [Member] | Level 3 [Member]
Derivatives Designated as Cash Flow Hedges [Abstract]
Vehicle fuel and other commodity	0		0
Other derivative instruments [Abstract]
Commodity trading	0		0
Natural gas commodity	0		0
Total current derivative assets	0		0
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0		0
Other derivative instruments [Abstract]
Commodity trading	0		0
Total noncurrent derivative assets	0		0
Other derivative instruments [Abstract]
Commodity trading	0		0
Natural gas commodity			0
Total current derivative liabilities	0		0
Other derivative instruments [Abstract]
Commodity trading	0		0
Total noncurrent derivative liabilities	0		0
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member]
Derivatives Designated as Cash Flow Hedges [Abstract]
Vehicle fuel and other commodity	42		43
Other derivative instruments [Abstract]
Commodity trading	4,746		6,432
Natural gas commodity	16		7
Total current derivative assets	4,804		6,482
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	39		39
Other derivative instruments [Abstract]
Commodity trading	1,209		3,768
Total noncurrent derivative assets	1,248		3,807
Other derivative instruments [Abstract]
Commodity trading	4,272		5,958
Natural gas commodity			85
Total current derivative liabilities	4,272		6,043
Other derivative instruments [Abstract]
Commodity trading	1,128		3,450
Total noncurrent derivative liabilities	1,128		3,450
Fair Value Measured on a Recurring Basis [Member] | Counterparty Netting [Member]
Derivatives Designated as Cash Flow Hedges [Abstract]
Vehicle fuel and other commodity	0	[2]	0	[2]
Other derivative instruments [Abstract]
Commodity trading	(2,282)	[2]	(3,301)	[2]
Natural gas commodity	0	[2]	(7)	[2]
Total current derivative assets	(2,282)	[2]	(3,308)	[2]
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0	[2]	0	[2]
Other derivative instruments [Abstract]
Commodity trading	(518)	[2]	(1,546)	[2]
Total noncurrent derivative assets	(518)	[2]	(1,546)	[2]
Other derivative instruments [Abstract]
Commodity trading	(1,869)	[2]	(2,712)	[2]
Natural gas commodity			(7)	[2]
Total current derivative liabilities	(1,869)	[2]	(2,719)	[2]
Other derivative instruments [Abstract]
Commodity trading	(518)	[2]	(1,546)	[2]
Total noncurrent derivative liabilities	$ (518)	[2]	$ (1,546)	[2]

[1] 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.

[2] PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2013 and Dec. 31, 2012. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating activities
Net income	$ 116,605	$ 93,285
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	90,809	84,948
Demand side management program amortization	1,257	1,392
Deferred income taxes	66,372	49,182
Amortization of investment tax credits	(740)	(651)
Allowance for equity funds used during construction	(5,923)	(2,726)
Net realized and unrealized hedging and derivative transactions	(164)	6,496
Changes in operating assets and liabilities:
Accounts receivable	41,048	30,996
Accrued unbilled revenues	49,579	112,150
Inventories	42,434	56,836
Prepayments and other	(10,662)	(3,250)
Accounts payable	(18,383)	(124,292)
Net regulatory assets and liabilities	67,907	10,147
Other current liabilities	10,870	39,057
Pension and other employee benefit obligations	(44,273)	(39,547)
Change in other noncurrent assets	3,779	(6,434)
Change in other noncurrent liabilities	1,720	(1,297)
Net cash provided by operating activities	412,235	306,292
Investing activities
Utility capital/construction expenditures	(226,948)	(152,420)
Allowance for equity funds used during construction	5,923	2,726
Investments in utility money pool arrangement	(276,000)	(383,000)
Repayments from utility money pool arrangement	76,000	363,000
Net cash used in investing activities	(421,025)	(169,694)
Financing activities
Repayments of short-term borrowings, net	(154,000)	0
Borrowings under utility money pool arrangement	14,000	0
Repayments under utility money pool arrangement	(14,000)	0
Proceeds from issuance of long-term debt	493,164	0
Repayments of long-term debt	(250,000)	0
Dividends paid to parent	(66,803)	(134,004)
Net cash provided by (used in) financing activities	22,361	(134,004)
Net change in cash and cash equivalents	13,571	2,594
Cash and cash equivalents at beginning of period	5,150	3,763
Cash and cash equivalents at end of period	18,721	6,357
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(54,770)	(44,384)
Cash (paid) received for income taxes, net	(16,308)	3,623
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$ 81,470	$ 60,020

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Commitments and Contingencies, Environmental Contingencies (Details) (Regional Haze Rules [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2010 Boiler Kiln Group	Mar. 31, 2013 Capital Commitments [Member]
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation		$ 340.9
Number of environmental groups who petitioned the U.S. Department of the Interior	2
Number of coal-fired boilers in Colorado	12
Number of coal-fired cement kilns in Colorado	1

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Selected Balance Sheet Data (Tables)

3 Months Ended

Mar. 31, 2013

Selected Balance Sheet Data [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	336,830		$	299,379
Less allowance for bad debts		(21,811	)		(21,918	)
	$	315,019		$	277,461

Inventories

(Thousands of Dollars)		March 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	55,748	$	54,486
Fuel		82,715		89,246
Natural gas		42,897		80,062
	$	181,360	$	223,794

Property, Plant and Equipment, Net

(Thousands of Dollars)		March 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	9,853,170		$	9,782,163
Natural gas plant		2,612,393			2,583,394
Common and other property		763,607			761,712
Plant to be retired (a)		141,038			152,730
Construction work in progress		616,858			506,225
Total property, plant and equipment		13,987,066			13,786,224
Less accumulated depreciation		(3,834,295	)		(3,755,233	)
	$	10,152,771		$	10,030,991

(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 2012, Cherokee Unit 1 was retired. Amounts are presented net of accumulated depreciation.

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Commitments and Contingencies, Legal Contingencies (Details) (USD $)	3 Months Ended						14 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Native Village of Kivalina vs. Xcel Energy Inc. et al. [Member]	Feb. 29, 2008 Native Village of Kivalina vs. Xcel Energy Inc. et al. [Member] Counterparty	Mar. 31, 2013 Comer vs. Xcel Energy Inc. et al. [Member]	May 31, 2011 Comer vs. Xcel Energy Inc. et al. [Member] Counterparty	Jun. 30, 2001 Pacific Northwest FERC Refund Proceeding [Member]	Mar. 31, 2013 Pacific Northwest FERC Refund Proceeding [Member]
Legal Contingencies [Abstract]
Number of other entities against which the native village of Kivalina has filed a lawsuit				23
Estimated cost of relocating the village of Kivalina, low end of range			$ 95,000,000
Estimated cost of relocating the village of Kivalina, high end of range			400,000,000
Accrual for legal contingency			0		0			0
Minimum number of utility, oil, chemical and coal companies against which a lawsuit was filed in U.S. District Court in Mississippi						85
Minimum amount of damages claimed by plaintiff								34,000,000
Sales to the City of Seattle	1,117,457,000	1,076,052,000					50,000,000
Estimated City of Seattle's claim for refunds not including interest								$ 28,000,000

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Rate Matters (Tables)

3 Months Ended

Mar. 31, 2013

Rate Matters [Abstract]

Major Adjustments to PSCo's Test Year in Colorado 2013 Gas Rate Case Proposed by the Staff and OCC

The CPUC Staff recommended a rate reduction of $14.4 million, based on a HTY, an ROE of 9 percent and an equity ratio of 52 percent and other adjustments. The OCC recommended a rate increase of $0.5 million based on a HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments. While the OCC did not recommend that the CPUC set rates using a FTY, they did calculate a revenue deficiency of $12.4 million for 2013. No other intervenor made ROE recommendations or specific recommendations regarding the revenue deficiency. The major adjustments to the test year proposed by the CPUC Staff and OCC are presented below.

(Millions of Dollars)	CPUC Staff			OCC
PSCo deficiency based on a HTY	$	28.3		$	28.3
ROE and capital structure adjustments		(20.8	)		(20.0	)
Move to a 13 month average from year end rate base		(5.7	)		(3.2	)
Remove pension asset		(5.9	)		-
Remove incentive compensation		(3.5	)		(0.2	)
Challenge known and measurable		-			(9.0	)
Eliminate depreciation annualization		-			(1.8	)
Revenue adjustments		(4.1	)		(1.4	)
Resulting tax impacts		1.5			4.7
Other adjustments		(4.2	)		3.1
Recommendation	$	(14.4	)	$	0.5

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 18,721	$ 5,150
Accounts receivable, net	315,019	277,461
Accounts receivable from affiliates	14,938	93,544
Investments in utility money pool arrangement	200,000	0
Accrued unbilled revenues	236,045	285,624
Inventories	181,360	223,794
Regulatory assets	146,980	143,689
Deferred income taxes	25,194	0
Derivative instruments	4,237	4,889
Prepayments and other	33,632	22,970
Total current assets	1,176,126	1,057,121
Property, plant and equipment, net	10,152,771	10,030,991
Other assets
Regulatory assets	916,822	934,728
Derivative instruments	8,908	10,868
Other	50,114	50,461
Total other assets	975,844	996,057
Total assets	12,304,741	12,084,169
Current liabilities
Current portion of long-term debt	6,477	256,297
Short-term debt	0	154,000
Accounts payable	332,212	359,969
Accounts payable to affiliates	26,556	30,001
Regulatory liabilities	68,331	33,723
Taxes accrued	186,670	153,614
Accrued interest	31,196	48,014
Dividends payable to parent	66,678	66,803
Derivative instruments	7,832	8,753
Other	65,952	72,669
Total current liabilities	791,904	1,183,843
Deferred credits and other liabilities
Deferred income taxes	1,878,873	1,782,828
Deferred investment tax credits	41,375	42,097
Regulatory liabilities	431,799	417,404
Asset retirement obligations	44,308	43,751
Derivative instruments	27,953	30,605
Customer advances	236,126	229,498
Pension and employee benefit obligations	280,314	324,625
Other	66,373	69,307
Total deferred credits and other liabilities	3,007,121	2,940,115
Commitments and contingencies
Capitalization
Long-term debt	3,870,164	3,374,476
Common stock - 100 shares authorized at $0.01 par value; 100 shares outstanding at March 31, 2013 and Dec. 31, 2012	0	0
Additional paid in capital	3,415,669	3,415,669
Retained earnings	1,242,865	1,192,937
Accumulated other comprehensive loss	(22,982)	(22,871)
Total common stockholder's equity	4,635,552	4,585,735
Total liabilities and equity	$ 12,304,741	$ 12,084,169

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Interest charges and financing costs
Other financing costs	$ 1,648	$ 1,790

XML

Fair Value of Financial Assets and Liabilities

3 Months Ended

Mar. 31, 2013

Fair Value of Financial Assets and Liabilities [Abstract]

Fair Value of Financial Assets and Liabilities

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.

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.

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.

Derivative Instruments Fair Value Measurements

PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage 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 March 31, 2013, 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, including forecasted amounts for any unsettled hedges.

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 March 31, 2013, PSCo had various vehicle fuel 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 other comprehensive income 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 months ended March 31, 2013 and 2012.

At March 31, 2013, 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.

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

The following table details the gross notional amounts of commodity forwards and options at March 31, 2013 and Dec. 31, 2012:

(Amounts in Thousands) (a)(b)	March 31, 2013		Dec. 31, 2012
Megawatt hours (MWh) of electricity		570		813
Million British thermal units (MMBtu) of natural gas		31		646
Gallons of vehicle fuel		284		307

(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.

Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts 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.

PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

PSCo's most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At March 31, 2013, four of PSCo's 10 most significant counterparties, comprising $28.6 million or 24 percent of this credit exposure at March 31, 2013, had investment grade credit ratings from Standard & Poor's, Moody's or Fitch Ratings. The remaining six significant counterparties, comprising $65.7 million or 56 percent of this credit exposure at March 31, 2013, were not rated by these agencies, but based on PSCo's internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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 March 31
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(22,871	)	$	(12,377	)
After-tax net unrealized gains related to derivatives accounted for as hedges		7			13,020
After-tax net realized gains on derivative transactions reclassified into earnings		(118	)		(375	)
Accumulated other comprehensive (loss) income related to cash flow hedges at March 31	$	(22,982	)	$	268

The following tables detail the impact of derivative activity during the three months ended March 31, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2013
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:				Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory (Assets) and Liabilities			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-	$	(180	)	(a)	$	-		$	-
Vehicle fuel and other commodity		11		-		(12	)	(d)		-			-
Total	$	11	$	-	$	(192	)		$	-		$	-
Other derivative instruments
Natural gas commodity	$	-	$	43	$	-			$	7	(c)	$	16	(b)
Total	$	-	$	43	$	-			$	7		$	16

	Three Months Ended March 31, 2012
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Income		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Income				Regulatory (Assets) and Liabilities			Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	20,917	$	-		$	(582	)	(a)	$	-		$	-
Vehicle fuel and other commodity		75		-			(23	)	(d)		-			-
Total	$	20,992	$	-		$	(605	)		$	-		$	-
Other derivative instruments
Natural gas commodity	$	-	$	(7,715	)	$	-			$	61,858	(c)	$	(109	)	(b)
Total	$	-	$	(7,715	)	$	-			$	61,858		$	(109	)

(a) Amounts are recorded to interest charges.

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

(c) Amounts for the three months ended March 31, 2012 included $5.0 million of settlement losses on derivatives entered 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. Such losses for the three months ended March 31, 2013 were immaterial. The remaining settlement losses for the three months ended March 31, 2013 and 2012 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 out of income to a regulatory asset, as appropriate.

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

PSCo had no derivative instruments designated as fair value hedges during the three months ended March 31, 2013 and 2012. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features—Contract provisions for 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 $2.4 million and $4.6 million gross liability position on the consolidated balance sheets at March 31, 2013 and Dec. 31, 2012, respectively, would have required PSCo to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $2.4 million and $4.6 million at March 31, 2013 and Dec. 31, 2012, respectively. At March 31, 2013 and Dec. 31, 2012, 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 March 31, 2013 and Dec. 31, 2012.

Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo's assets and liabilities measured at fair value on a recurring basis at March 31, 2013:

	March 31, 2013
	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	$	-	$	42	$	-	$	42	$	-		$	42
Other derivative instruments:
Commodity trading		-		4,746		-		4,746		(2,282	)		2,464
Natural gas commodity		-		16		-		16		-			16
Total current derivative assets	$	-	$	4,804	$	-	$	4,804	$	(2,282	)		2,522
Purchased power agreements (a)													1,715
Current derivative instruments												$	4,237
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	39	$	-	$	39	$	-		$	39
Other derivative instruments:
Commodity trading		-		1,209		-		1,209		(518	)		691
Total noncurrent derivative assets	$	-	$	1,248	$	-	$	1,248	$	(518	)		730
Purchased power agreements (a)													8,178
Noncurrent derivative instruments												$	8,908
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	-	$	4,272	$	-	$	4,272	$	(1,869	)	$	2,403
Total current derivative liabilities	$	-	$	4,272	$	-	$	4,272	$	(1,869	)		2,403
Purchased power agreements (a)													5,429
Current derivative instruments												$	7,832
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	1,128	$	-	$	1,128	$	(518	)	$	610
Total noncurrent derivative liabilities	$	-	$	1,128	$	-	$	1,128	$	(518	)		610
Purchased power agreements (a)													27,343
Noncurrent derivative instruments												$	27,953

(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) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2013 and Dec. 31, 2012. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents, for each of the fair value hierarchy levels, PSCo's assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012:

	Dec. 31, 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	$	-	$	43	$	-	$	43	$	-		$	43
Other derivative instruments:
Commodity trading		-		6,432		-		6,432		(3,301	)		3,131
Natural gas commodity		-		7		-		7		(7	)		-
Total current derivative assets	$	-	$	6,482	$	-	$	6,482	$	(3,308	)		3,174
Purchased power agreements (a)													1,715
Current derivative instruments												$	4,889
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	39	$	-	$	39	$	-		$	39
Other derivative instruments:
Commodity trading		-		3,768		-		3,768		(1,546	)		2,222
Total noncurrent derivative assets	$	-	$	3,807	$	-	$	3,807	$	(1,546	)		2,261
Purchased power agreements (a)													8,607
Noncurrent derivative instruments												$	10,868
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	5,958	$	-	$	5,958	$	(2,712	)	$	3,246
Natural gas commodity		-		85		-		85		(7	)		78
Total current derivative liabilities	$	-	$	6,043	$	-	$	6,043	$	(2,719	)		3,324
Purchased power agreements (a)													5,429
Current derivative instruments												$	8,753
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	3,450	$	-	$	3,450	$	(1,546	)	$	1,904
Total noncurrent derivative liabilities	$	-	$	3,450	$	-	$	3,450	$	(1,546	)		1,904
Purchased power agreements (a)													28,701
Noncurrent derivative instruments												$	30,605

(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) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2013 and Dec. 31, 2012. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were no changes in Level 3 recurring fair value measurements for the three months ended March 31, 2013 and 2012.

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for the three months ended March 31, 2013 and 2012.

Fair Value of Long-Term Debt

As of March 31, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2013				Dec. 31, 2012
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,876,641	$	4,323,766	$	3,630,773	$	4,131,866

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 March 31, 2013 and Dec. 31, 2012, 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.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2013	May 06, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	PUBLIC SERVICE CO OF COLORADO
Entity Central Index Key	0000081018
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		100
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013

XML

Other Income, Net

3 Months Ended

Mar. 31, 2013

Other Income, Net [Abstract]

Other Income, Net

9. Other Income, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2013			2012
Interest income	$	914		$	1,028
Other nonoperating income		882			568
Insurance policy expense		(219	)		(564	)
Other income, net	$	1,577		$	1,032

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Comprehensive income:
Net income	$ 116,605	$ 93,285
Derivative instruments:
Net fair value increase, net of tax of $4 and $7,972, respectively	7	13,020
Reclassification of gains to net income, net of tax of $(74) and $(230), respectively	(118)	(375)
Total derivative instruments, net of tax	(111)	12,645
Other comprehensive (loss) income	(111)	12,645
Comprehensive income	$ 116,494	$ 105,930

XML

Selected Balance Sheet Data

3 Months Ended

Mar. 31, 2013

Selected Balance Sheet Data [Abstract]

Selected Balance Sheet Data

3. Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	336,830		$	299,379
Less allowance for bad debts		(21,811	)		(21,918	)
	$	315,019		$	277,461

(Thousands of Dollars)		March 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	55,748	$	54,486
Fuel		82,715		89,246
Natural gas		42,897		80,062
	$	181,360	$	223,794

(Thousands of Dollars)		March 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	9,853,170		$	9,782,163
Natural gas plant		2,612,393			2,583,394
Common and other property		763,607			761,712
Plant to be retired (a)		141,038			152,730
Construction work in progress		616,858			506,225
Total property, plant and equipment		13,987,066			13,786,224
Less accumulated depreciation		(3,834,295	)		(3,755,233	)
	$	10,152,771		$	10,030,991

(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 2012, Cherokee Unit 1 was retired. Amounts are presented net of accumulated depreciation.

XML

Accounting Pronouncements

3 Months Ended

Mar. 31, 2013

Accounting Pronouncements [Abstract]

Accounting Pronouncements

2. Accounting Pronouncements

Recently Adopted

Balance Sheet Offsetting — In December 2011, the Financial Accounting Standards Board (FASB) issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (Accounting Standards Update (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. In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods. PSCo implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 8 for the required disclosures.

Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated other comprehensive income and amounts reclassified out of accumulated other comprehensive income. These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements. These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods. PSCo implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 12 for the required disclosures.

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2013

Income Taxes [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	March 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	1.2	$	1.3
Unrecognized tax benefit — Temporary tax positions		8.5		8.3
Total unrecognized tax benefit	$	9.7	$	9.6

Tax Benefits Associated with NOL and Tax Credit Carryforwards

The unrecognized tax benefit amounts were 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)	March 31, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(6.2	)	$	(5.3	)

XML

Segment Information

3 Months Ended

Mar. 31, 2013

Segment Information [Abstract]

Segment Information

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 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.

	Regulated		Regulated			All			Reconciling				Consolidated
(Thousands of Dollars)	Electric			Natural Gas			Other			Eliminations				Total
Three Months Ended March 31, 2013
Operating revenues from external customers	$	721,348		$	383,924		$	12,185		$	-			$	1,117,457
Intersegment revenues		88			47			-			(135	)			-
Total revenues	$	721,436		$	383,971		$	12,185		$	(135	)		$	1,117,457
Net income	$	78,468		$	33,799		$	4,338		$	-			$	116,605

	Regulated		Regulated			All			Reconciling				Consolidated
(Thousands of Dollars)	Electric			Natural Gas			Other			Eliminations				Total
Three Months Ended March 31, 2012
Operating revenues from external customers	$	682,279		$	383,004		$	10,769		$	-			$	1,076,052
Intersegment revenues		92			55			-			(147	)			-
Total revenues	$	682,371		$	383,059		$	10,769		$	(147	)		$	1,076,052
Net income	$	61,333		$	28,310		$	3,642		$	-			$	93,285

XML

Commitments and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies [Abstract]

Commitments and Contingencies

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, 2012, 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 that own natural gas fueled power plants for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific purchased power agreements create a variable interest in the associated independent power producing entity.

PSCo had approximately 1,433 megawatts (MW) of capacity under long-term purchased power agreements as of March 31, 2013 and Dec. 31, 2012 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.

Environmental Contingencies

Regional Haze Rules — In 2005, the U.S. Environmental Protection Agency (EPA) finalized amendments to its regional haze rules, known as best available retrofit technology (BART), which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. 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 emissions under BART and then set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a 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. The CMA appealed this decision, which is now pending in the Colorado Court of Appeals.

In September 2012, the EPA granted final approval of the 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 $340.9 million. PSCo expects the cost of any required capital investment will be recoverable from customers.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10th Circuit to review the EPA's decision approving the SIP. WildEarth Guardians has stated that it will challenge the BART determination made for Comanche Units 1 and 2, which was a separate determination that was not part of the CACJA emission reduction plan. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent, or that selective catalytic reduction be added to the units. PSCo has intervened in the case.

In 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 Clean Air Act 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.

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 is 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 when (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. Unless otherwise required by GAAP, legal fees are expensed as incurred.

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 and 23 other utility, oil, gas and coal companies. Plaintiffs claim that defendants' emission of carbon dioxide (CO2) and other greenhouse gases contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss 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 and subsequently rejected plaintiffs' request for rehearing. Plaintiffs subsequently filed a petition for review with the United States Supreme Court. It is unknown whether the United States Supreme Court will grant 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 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., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota. The amount of damages claimed by plaintiffs is unknown. The defendants 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. Oral arguments occurred in May 2013. It is uncertain when the Fifth Circuit will issue its decision. Although Xcel Energy 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.

Employment, Tort and Commercial Litigation

Pacific Northwest Federal Energy Regulatory Commission (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 Ninth Circuit.

In an order issued in August 2007, 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 Ninth Circuit 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 claiming refunds for the period January 2000 through June 2001. Seattle indicated that for the period June 2000 through June 2001 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. PSCo submitted its answering case in December 2012.

On April 5, 2013, the FERC issued an order on rehearing of its remand order issued for the October 2011 review proceedings. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to meet to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear whether Seattle has a claim against PSCo prior to June 2000.

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. First, not withstanding 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 the FERC's standard will likely be challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter.

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Income Taxes

3 Months Ended

Mar. 31, 2013

Income Taxes [Abstract]

Income Taxes

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, 2012 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 June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011. As of March 31, 2013, the IRS had not proposed any material adjustments to 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 March 31, 2013, PSCo's earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006. In the fourth quarter of 2012, the state of Colorado commenced an examination of tax years 2006 through 2009. As of March 31, 2013, no material adjustments had been proposed for these years. There are currently no other 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)	March 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	1.2	$	1.3
Unrecognized tax benefit — Temporary tax positions		8.5		8.3
Total unrecognized tax benefit	$	9.7	$	9.6

The unrecognized tax benefit amounts were 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)	March 31, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(6.2	)	$	(5.3	)

It is reasonably possible that PSCo's amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $9 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2013 and Dec. 31, 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2013 or Dec. 31, 2012.

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Rate Matters

3 Months Ended

Mar. 31, 2013

Rate Matters [Abstract]

Rate Matters

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, 2012 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending and Recently Concluded Regulatory Proceedings — CPUC

Base Rate

Colorado 2013 Gas Rate Case —In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015. The request is based on a 2013 forecast test year, a 10.5 percent return on equity (ROE), a rate base of $1.3 billion and an equity ratio of 56 percent. PSCo is requesting an extension of its Pipeline System Integrity Adjustment (PSIA) rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects. PSCo estimates that the PSIA will increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue. In conjunction with the multi-year base rate step increases, PSCo is proposing a stay-out provision and an earnings test through the end of 2015 with a commitment to file a rate case to implement revised rates on Jan. 1, 2016.

In January 2013, the CPUC suspended the tariff filing and set the case for hearing. In order to accommodate the procedural schedule, rates will go into effect as filed on Aug. 10, 2013, subject to refund for the difference between the filed rates and the rates approved in the final CPUC order in the case.

On April 3, 2013, four parties filed answer testimony in the natural gas case. The CPUC Staff and Office of Consumer Counsel (OCC) recommended changes to the level of integrity management costs moved from the PSIA rider to base rates. For clarity, PSCo will present base rate recommendations relative to deficiencies without the PSIA revenues to isolate the base rate impacts of the recommendations. PSCo's 2013 deficiency based on a Forecasted Test Year (FTY) net of PSIA changes was $45 million for 2013 and the revenue deficiency was $28.3 million based on a Historic Test Year (HTY).

The CPUC Staff recommended a rate reduction of $14.4 million, based on a HTY, an ROE of 9 percent and an equity ratio of 52 percent and other adjustments. The OCC recommended a rate increase of $0.5 million based on a HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments. While the OCC did not recommend that the CPUC set rates using a FTY, they did calculate a revenue deficiency of $12.4 million for 2013. No other intervenor made ROE recommendations or specific recommendations regarding the revenue deficiency. The major adjustments to the test year proposed by the CPUC Staff and OCC are presented below.

(Millions of Dollars)	CPUC Staff			OCC
PSCo deficiency based on a HTY	$	28.3		$	28.3
ROE and capital structure adjustments		(20.8	)		(20.0	)
Move to a 13 month average from year end rate base		(5.7	)		(3.2	)
Remove pension asset		(5.9	)		-
Remove incentive compensation		(3.5	)		(0.2	)
Challenge known and measurable		-			(9.0	)
Eliminate depreciation annualization		-			(1.8	)
Revenue adjustments		(4.1	)		(1.4	)
Resulting tax impacts		1.5			4.7
Other adjustments		(4.2	)		3.1
Recommendation	$	(14.4	)	$	0.5

On April 26, 2013, the CPUC Staff filed supplemental testimony recommending an additional net disallowance of $1.6 million for adjustments and corrections.

On April 29, 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. PSCo refutes the recommendations of the CPUC Staff and the OCC to disallow known and measurable adjustments and otherwise change regulatory precedent including moving from end of year rate base to average rate base for a HTY, removing the pension asset, removing incentive compensation and moving to an imputed capital structure. PSCo agreed to recover approximately $3.5 million of revenue requirement in the PSIA, rather than through base rates and accepted the CPUC Staff's recommendation to use deferred accounting to accommodate property tax increases.

Hearings are expected to start in May 2013 and a decision is expected in the third quarter of 2013.

Colorado 2013 Steam Rate Case —In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015. The request is based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent. Final rates are expected to be effective in the third quarter of 2013.

Next steps in the procedural schedule are expected to be as follows:

• Staff/Intervenor Direct Testimony – Aug. 7, 2013

• Rebuttal Testimony and Reverse Cross-Answer Testimony – Aug. 28, 2013

• Evidentiary Hearings – Sept. 23-27, 2013

• Post-Hearing Statement Position – Oct. 11, 2013

• Proposed Findings – prior to Dec. 31, 2013

2011 Electric Rate Case Earnings Test — On April 1, 2013, PSCo filed a tariff implementing the earnings sharing mechanism compliance with the settlement and CPUC decision for PSCo's 2011 electric rate case. The earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year over PSCo's authorized ROE threshold of 10 percent. Based on the filing, PSCo's earnings did not exceed the established threshold. Any party disputing the calculation must file a notice with the CPUC identifying all issues by May 15, 2013.

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 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. For the three months ended March 31, 2013 and 2012, PSCo credited the RESA regulatory asset balance $4.0 million and $28.7 million, respectively. The cumulative credit to the RESA regulatory asset balance was $86.8 million and $82.8 million at March 31, 2013 and Dec. 31, 2012, respectively. The credits include the customers' share of REC trading margins and the customers' share of carbon offset funds.

This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and evidence regarding actual deliveries.

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Borrowings and Other Financing Instruments

3 Months Ended

Mar. 31, 2013

Borrowings and Other Financing Instruments [Abstract]

Borrowings and Other Financing Instruments

7.  Borrowings and Other Financing Instruments

Short-Term Borrowings

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. Money pool borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250		$	250
Amount outstandingat period end		-			-
Average amount outstanding		1			0.3
Maximum amount outstanding		12			8
Weighted average interest rate, computed on a daily basis		0.36	%		0.33	%
Weighted average interest rate at period end		N/A			N/A

Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for PSCo was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700		$	700
Amount outstandingat period end		-			154
Average amount outstanding		154			8
Maximum amount outstanding		332			165
Weighted average interest rate, computed on a daily basis		0.34	%		0.33	%
Weighted average interest rate at period end		N/A			0.35

Letters of Credit — PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At both March 31, 2013 and Dec. 31, 2012, there were $4.0 million of letters of credit outstanding. 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 March 31, 2013, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility(a)		Drawn (b)		Available
$	700.0	$	4.0	$	696.0

(a) Credit facility expires in July 2017.

(b) Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at March 31, 2013 and Dec. 31, 2012.

Long-Term Borrowings

In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023, as well as $250 million of 3.95 percent first mortgage bonds due March 15, 2043.

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Commitments and Contingencies, Purchased Power Agreements (Details)	Mar. 31, 2013 MW	Dec. 31, 2012 MW
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,433	1,433

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Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive loss at beginning of period	$ (22,871)
Accumulated other comprehensive loss at end of period	(22,982)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	41,388		48,291
Operating and maintenance expenses	173,041		168,382
Total, pre-tax	(180,562)		(145,534)
Tax benefit	63,957		52,249
Gains and Losses on Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive loss at beginning of period	(22,871)
Other comprehensive income (loss) before reclassifications	7
(Gains) losses reclassified from net accumulated other comprehensive loss	(118)
Net current period other comprehensive loss	(111)
Accumulated other comprehensive loss at end of period	(22,982)
Gains and Losses on Cash Flow Hedges [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	(192)
Tax benefit	74
Total, net of tax	(118)
Gains and Losses on Cash Flow Hedges [Member] | Interest Rate Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	(180)	[1]
Gains and Losses on Cash Flow Hedges [Member] | Vehicle Fuel And Other Commodity Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	$ (12)	[2]

[1] Included in interest charges.

[2] Included in O&M expenses.

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Other Comprehensive Income

3 Months Ended

Mar. 31, 2013

Other Comprehensive Income [Abstract]

Other Comprehensive Income

12. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(22,871	)
Other comprehensive income before reclassifications		7
Gains reclassified from net accumulated other comprehensive loss		(118	)
Net current period other comprehensive loss		(111	)
Accumulated other comprehensive loss at March 31	$	(22,982	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2013 were as follows:

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
Gains on cash flow hedges:
Interest rate derivatives	$	(180	) (a)
Vehicle fuel derivatives		(12	) (b)
Total, pre-tax		(192	)
Tax expense		74
Total amounts reclassified, net of tax	$	(118	)

(a) Included in interest charges.

(b) Included in O&M expenses.

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Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value of Financial Assets and Liabilities [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

The following table details the gross notional amounts of commodity forwards and options at March 31, 2013 and Dec. 31, 2012:

(Amounts in Thousands) (a)(b)	March 31, 2013		Dec. 31, 2012
Megawatt hours (MWh) of electricity		570		813
Million British thermal units (MMBtu) of natural gas		31		646
Gallons of vehicle fuel		284		307

(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 on Accumulated Other Comprehensive Loss

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 March 31
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(22,871	)	$	(12,377	)
After-tax net unrealized gains related to derivatives accounted for as hedges		7			13,020
After-tax net realized gains on derivative transactions reclassified into earnings		(118	)		(375	)
Accumulated other comprehensive (loss) income related to cash flow hedges at March 31	$	(22,982	)	$	268

Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income

The following tables detail the impact of derivative activity during the three months ended March 31, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2013
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:				Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory (Assets) and Liabilities			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-	$	(180	)	(a)	$	-		$	-
Vehicle fuel and other commodity		11		-		(12	)	(d)		-			-
Total	$	11	$	-	$	(192	)		$	-		$	-
Other derivative instruments
Natural gas commodity	$	-	$	43	$	-			$	7	(c)	$	16	(b)
Total	$	-	$	43	$	-			$	7		$	16

	Three Months Ended March 31, 2012
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Income		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Income				Regulatory (Assets) and Liabilities			Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	20,917	$	-		$	(582	)	(a)	$	-		$	-
Vehicle fuel and other commodity		75		-			(23	)	(d)		-			-
Total	$	20,992	$	-		$	(605	)		$	-		$	-
Other derivative instruments
Natural gas commodity	$	-	$	(7,715	)	$	-			$	61,858	(c)	$	(109	)	(b)
Total	$	-	$	(7,715	)	$	-			$	61,858		$	(109	)

(a) Amounts are recorded to interest charges.

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

(c) Amounts for the three months ended March 31, 2012 included $5.0 million of settlement losses on derivatives entered 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. Such losses for the three months ended March 31, 2013 were immaterial. The remaining settlement losses for the three months ended March 31, 2013 and 2012 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 out of income to a regulatory asset, as appropriate.

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

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo's assets and liabilities measured at fair value on a recurring basis at March 31, 2013:

	March 31, 2013
	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	$	-	$	42	$	-	$	42	$	-		$	42
Other derivative instruments:
Commodity trading		-		4,746		-		4,746		(2,282	)		2,464
Natural gas commodity		-		16		-		16		-			16
Total current derivative assets	$	-	$	4,804	$	-	$	4,804	$	(2,282	)		2,522
Purchased power agreements (a)													1,715
Current derivative instruments												$	4,237
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	39	$	-	$	39	$	-		$	39
Other derivative instruments:
Commodity trading		-		1,209		-		1,209		(518	)		691
Total noncurrent derivative assets	$	-	$	1,248	$	-	$	1,248	$	(518	)		730
Purchased power agreements (a)													8,178
Noncurrent derivative instruments												$	8,908
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	-	$	4,272	$	-	$	4,272	$	(1,869	)	$	2,403
Total current derivative liabilities	$	-	$	4,272	$	-	$	4,272	$	(1,869	)		2,403
Purchased power agreements (a)													5,429
Current derivative instruments												$	7,832
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	1,128	$	-	$	1,128	$	(518	)	$	610
Total noncurrent derivative liabilities	$	-	$	1,128	$	-	$	1,128	$	(518	)		610
Purchased power agreements (a)													27,343
Noncurrent derivative instruments												$	27,953

(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) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2013 and Dec. 31, 2012. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents, for each of the fair value hierarchy levels, PSCo's assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012:

	Dec. 31, 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	$	-	$	43	$	-	$	43	$	-		$	43
Other derivative instruments:
Commodity trading		-		6,432		-		6,432		(3,301	)		3,131
Natural gas commodity		-		7		-		7		(7	)		-
Total current derivative assets	$	-	$	6,482	$	-	$	6,482	$	(3,308	)		3,174
Purchased power agreements (a)													1,715
Current derivative instruments												$	4,889
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	39	$	-	$	39	$	-		$	39
Other derivative instruments:
Commodity trading		-		3,768		-		3,768		(1,546	)		2,222
Total noncurrent derivative assets	$	-	$	3,807	$	-	$	3,807	$	(1,546	)		2,261
Purchased power agreements (a)													8,607
Noncurrent derivative instruments												$	10,868
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	5,958	$	-	$	5,958	$	(2,712	)	$	3,246
Natural gas commodity		-		85		-		85		(7	)		78
Total current derivative liabilities	$	-	$	6,043	$	-	$	6,043	$	(2,719	)		3,324
Purchased power agreements (a)													5,429
Current derivative instruments												$	8,753
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	3,450	$	-	$	3,450	$	(1,546	)	$	1,904
Total noncurrent derivative liabilities	$	-	$	3,450	$	-	$	3,450	$	(1,546	)		1,904
Purchased power agreements (a)													28,701
Noncurrent derivative instruments												$	30,605

(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) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2013 and Dec. 31, 2012. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Carrying Amount and Fair Value of Long-term Debt

As of March 31, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2013				Dec. 31, 2012
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,876,641	$	4,323,766	$	3,630,773	$	4,131,866

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Segment Reporting Information [Line Items]
Operating revenues	$ 1,117,457	$ 1,076,052
Net income	116,605	93,285
Regulated Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues	721,348	682,279
Net income	78,468	61,333
Regulated Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues	383,924	383,004
Net income	33,799	28,310
All Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	12,185	10,769
Net income	4,338	3,642
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	1,117,457	1,076,052
Operating Segments [Member] | Regulated Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues	721,436	682,371
Operating Segments [Member] | Regulated Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues	383,971	383,059
Operating Segments [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	12,185	10,769
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(135)	(147)
Net income	0	0
Intersegment Eliminations [Member] | Regulated Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues	88	92
Intersegment Eliminations [Member] | Regulated Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues	47	55
Intersegment Eliminations [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013 MWh		Dec. 31, 2012 MWh
Credit Concentration Risk [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	10
Credit Concentration Risk [Member] | Investment Grade Ratings from Standard & Poor's, Moody's, or Fitch Ratings [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	28.6
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	24.00%
Credit Concentration Risk [Member] | No Investment Grade Ratings from External Credit Rating Agencies [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	6
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	65.7
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	56.00%
Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months	0.5
Electric Commodity [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	570,000	[1],[2]	813,000	[1],[2]
Natural Gas Commodity [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	31,000	[1],[2]	646,000	[1],[2]
Vehicle Fuel Commodity [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	284,000	[1],[2]	307,000	[1],[2]

[1] Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

[2] Amounts are not reflective of net positions in the underlying commodities.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative instruments:
Net fair value increase, tax	$ 4	$ 7,972
Reclassification of gains to net income, tax	$ (74)	$ (230)

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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, 2012, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Other Income, Net (Tables)

3 Months Ended

Mar. 31, 2013

Other Income, Net [Abstract]

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2013			2012
Interest income	$	914		$	1,028
Other nonoperating income		882			568
Insurance policy expense		(219	)		(564	)
Other income, net	$	1,577		$	1,032

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Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Letters of Credit [Abstract]
Terms of letters of credit (in years)	1 year
Letters of credit outstanding under credit facilities	$ 4.0	$ 4.0

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Benefit Plans and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2013

Benefit Plans and Other Postretirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

11.  Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	2013			2012			2013			2012
(Thousands of Dollars)		Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,302		$	5,497		$	803		$	823
Interest cost		11,540			12,624			5,934			6,142
Expected return on plan assets		(15,955	)		(16,235	)		(7,307	)		(6,270	)
Amortization of transition obligation		-			-			196			2,751
Amortization of prior service (credit) cost		(266	)		57			(1,229	)		(1,288	)
Amortization of net loss		10,854			8,305			3,490			2,604
Net periodic benefit cost		12,475			10,248			1,887			4,762
Additional cost recognized due to the effects of regulation		-			-			-			973
Net benefit cost recognized for financial reporting	$	12,475		$	10,248		$	1,887		$	5,735

In January 2013, contributions of $191.5 million were made across four of Xcel Energy's pension plans, of which $44.3 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2013.