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 September 30, 2013

or

¨ 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 ¨ 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 ¨ 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 ¨	Accelerated filer ¨
Non-accelerated filer x	Smaller reporting company ¨
(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). ¨ Yes x No

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

Class	Outstanding at Oct. 28, 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	25
Item 4 —	Controls and Procedures	30
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	30
Item 1A —	Risk Factors	30
Item 4 —	Mine Safety Disclosures	30
Item 5 —	Other Information	30
Item 6 —	Exhibits	31
SIGNATURES		32
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

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

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2013			2012			2013			2012
Operating revenues
Electric	$	898,811		$	870,975		$	2,368,041		$	2,267,905
Natural gas	137,349			113,230			730,569			643,632
Steam and other	8,140			8,082			29,576			26,303
Total operating revenues	1,044,300			992,287			3,128,186			2,937,840
Operating expenses
Electric fuel and purchased power	355,727			315,319			998,395			920,916
Cost of natural gas sold and transported	43,881			24,662			403,198			338,630
Cost of sales — steam and other	3,398			3,650			12,211			10,745
Operating and maintenance expenses	192,073			180,994			553,266			529,476
Demand side management program expenses	38,016			33,670			104,075			92,462
Depreciation and amortization	88,577			85,905			267,206			249,645
Taxes (other than income taxes)	32,887			32,696			104,120			99,359
Total operating expenses	754,559			676,896			2,442,471			2,241,233
Operating income	289,741			315,391			685,715			696,607
Other income, net	946			1,000			3,845			3,582
Allowance for funds used during construction —  equity	8,815			4,687			21,529			10,961
Interest charges and financing costs
Interest charges — includes other financing costs of $1,747, $1,803,  $5,118 and $5,383, respectively	43,187			49,369			127,806			145,734
Allowance for funds used during construction — debt	(3,187		)	(2,633		)	(8,438		)	(5,328		)
Total interest charges and financing costs	40,000			46,736			119,368			140,406
Income before income taxes	259,502			274,342			591,721			570,744
Income taxes	93,236			81,899			211,551			189,609
Net income	$	166,266		$	192,443		$	380,170		$	381,135

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2013			2012			2013			2012
Net income	$	166,266		$	192,443		$	380,170		$	381,135
Other comprehensive loss
Derivative instruments:
Net fair value increase (decrease), net of tax of $5, $(2,197), $(2), and $(5,710), respectively	11			(3,574		)	(2		)	(9,311		)
Reclassification of gains to net income, net of tax of $(76), $(186), $(221), and $(646), respectively	(119		)	(304		)	(355		)	(1,055		)
Other comprehensive loss	(108		)	(3,878		)	(357		)	(10,366		)
Comprehensive income	$	166,158		$	188,565		$	379,813		$	370,769

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Nine Months Ended Sept. 30
	2013			2012
Operating activities
Net income	$	380,170		$	381,135
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	271,150			253,764
Demand side management program amortization	3,658			4,042
Deferred income taxes	230,665			179,254
Amortization of investment tax credits	(2,219		)	(1,955		)
Allowance for equity funds used during construction	(21,529		)	(10,961		)
Net realized and unrealized hedging and derivative transactions	(9,052		)	(39,241		)
Changes in operating assets and liabilities:
Accounts receivable	61,660			50,612
Accrued unbilled revenues	80,347			110,880
Inventories	(28,021		)	11,553
Prepayments and other	5,818			(33,967		)
Accounts payable	(28,581		)	(83,400		)
Net regulatory assets and liabilities	74,709			(66,007		)
Other current liabilities	(16,662		)	(8,444		)
Pension and other employee benefit obligations	(44,101		)	(59,154		)
Change in other noncurrent assets	6,917			(8,730		)
Change in other noncurrent liabilities	7,744			(505		)
Net cash provided by operating activities	972,673			678,876
Investing activities
Utility capital/construction expenditures	(742,822		)	(610,309		)
Allowance for equity funds used during construction	21,529			10,961
Investments in utility money pool arrangement	(1,086,000		)	(820,000		)
Repayments from utility money pool arrangement	951,000			752,000
Net cash used in investing activities	(856,293		)	(667,348		)
Financing activities
Repayments of short-term borrowings, net	(154,000		)	—
Borrowings under utility money pool arrangement	14,000			36,000
Repayments under utility money pool arrangement	(14,000		)	(36,000		)
Proceeds from issuance of long-term debt	492,372			791,007
Repayments of long-term debt	(250,000		)	—
Capital contributions from parent	4,485			28,122
Dividends paid to parent	(198,941		)	(200,501		)
Net cash (used in) provided by financing activities	(106,084		)	618,628
Net change in cash and cash equivalents	10,296			630,156
Cash and cash equivalents at beginning of period	5,150			3,763
Cash and cash equivalents at end of period	$	15,446		$	633,919
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(131,378	)	$	(133,667	)
Cash received (paid) for income taxes, net	41,531			(51,240		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	100,475		$	79,597

See Notes to Consolidated Financial Statements

5

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	Sept. 30, 2013			Dec. 31, 2012
Assets
Current assets
Cash and cash equivalents	$	15,446		$	5,150
Accounts receivable, net	282,823			277,461
Accounts receivable from affiliates	26,235			93,544
Investments in utility money pool arrangement	135,000			—
Accrued unbilled revenues	205,277			285,624
Inventories	251,234			223,794
Regulatory assets	142,973			143,689
Deferred income taxes	63,784			—
Derivative instruments	8,181			4,889
Prepayments and other	18,504			22,970
Total current assets	1,149,457			1,057,121
Property, plant and equipment, net	10,501,875			10,030,991
Other assets
Regulatory assets	904,546			934,728
Derivative instruments	7,333			10,868
Other	50,000			50,461
Total other assets	961,879			996,057
Total assets	$	12,613,211		$	12,084,169
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	281,906		$	256,297
Short-term debt	—			154,000
Accounts payable	332,775			359,969
Accounts payable to affiliates	34,800			30,001
Regulatory liabilities	47,204			33,723
Taxes accrued	158,996			153,614
Accrued interest	31,838			48,014
Dividends payable to parent	65,000			66,803
Derivative instruments	8,084			8,753
Other	68,528			72,669
Total current liabilities	1,029,131			1,183,843
Deferred credits and other liabilities
Deferred income taxes	2,091,827			1,782,828
Deferred investment tax credits	39,926			42,097
Regulatory liabilities	428,344			417,404
Asset retirement obligations	44,505			43,751
Derivative instruments	24,663			30,605
Customer advances	241,705			229,498
Pension and employee benefit obligations	280,486			324,625
Other	67,614			69,307
Total deferred credits and other liabilities	3,219,070			2,940,115
Commitments and contingencies
Capitalization
Long-term debt	3,592,116			3,374,476
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at Sept. 30, 2013 and Dec. 31, 2012	—			—
Additional paid in capital	3,420,154			3,415,669
Retained earnings	1,375,968			1,192,937
Accumulated other comprehensive loss	(23,228		)	(22,871		)
Total common stockholder’s equity	4,772,894			4,585,735
Total liabilities and equity	$	12,613,211		$	12,084,169

See Notes to Consolidated Financial Statements

6

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of Sept. 30, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2013 and 2012; and its cash flows for the nine months ended Sept. 30, 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 Sept. 30, 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)	Sept. 30, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	305,360		$	299,379
Less allowance for bad debts	(22,537		)	(21,918		)
	$	282,823		$	277,461

(Thousands of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	55,869	$	54,486
Fuel	86,597		89,246
Natural gas	108,768		80,062
	$	251,234	$	223,794

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	10,045,683		$	9,782,163
Natural gas plant	2,662,749			2,583,394
Common and other property	749,437			761,712
Plant to be retired (a)	115,753			152,730
Construction work in progress	850,106			506,225
Total property, plant and equipment	14,423,728			13,786,224
Less accumulated depreciation	(3,921,853		)	(3,755,233		)
	$	10,501,875		$	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 Sept. 30, 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 Sept. 30, 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 Sept. 30, 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)	Sept. 30, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	1.3
Unrecognized tax benefit — Temporary tax positions	9.4		8.3
Total unrecognized tax benefit	$	11.8	$	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)	Sept. 30, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(7.8	)	$	(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 Sept. 30, 2013 and Dec. 31, 2012 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2013 or Dec. 31, 2012.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As PSCo had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.

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 and in Note 5 to PSCo’s Quarterly Reports on Form 10-Q for the quarter periods ended March 31, 2013 and June 30, 2013, 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

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 (FTY), 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. Interim rates, subject to refund, went into effect in August 2013.

In April 2013, four parties filed answer testimony in the natural gas case.  The CPUC Staff recommended an incremental base revenue decrease of $1.1 million, based on a historic test year (HTY), an ROE of 9 percent and an equity ratio of 52 percent.  The Office of Consumer Counsel (OCC) recommended an incremental base revenue increase of $15.4 million based on an HTY, an ROE of 9 percent and an equity ratio of 51.03 percent and other adjustments. The recommended incremental base revenues are inclusive of proposed changes to the level of integrity management costs moved from the PSIA rider to base rates. 

In April 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, with subsequent step increases of $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. This requested increase includes amounts to be transferred from the PSIA rider mechanism. The deficiency, based on an FTY, was $30.6 million.

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In October 2013, the administrative law judge (ALJ) issued her recommendation. As part of this decision, she recommended the use of an HTY, an ROE of 9.72 percent and an equity ratio of 56 percent. The ALJ also recommended to reject PSCo's proposed changes to the PSIA, instead leaving the current rider in effect and suggested that changes be presented in a separate application. The recommended incremental base revenue increase was approximately $15.0 million.

The following table summarizes the CPUC Staff, OCC and ALJ's recommendations:

(Millions of Dollars)	CPUC Staff			OCC			ALJ
PSCo deficiency based on a FTY	$	44.8		$	44.8		$	44.8
Move to HTY	(1.6		)	(1.6		)	(1.6		)
ROE and capital structure adjustments	(20.8		)	(20.0		)	(7.7		)
Move to a 13 month average from year end rate base	(5.7		)	(3.2		)	(3.3		)
Remove pension asset	(5.9		)	—			—
Reduce pension expense net of corrections	(1.6		)	—			—
Remove incentive compensation	(3.5		)	(0.2		)	(0.2		)
Challenge known and measurable	—			(9.0		)	—
Eliminate depreciation annualization	—			(1.8		)	—
Revenue adjustments	(4.1		)	(1.4		)	(1.4		)
Resulting tax impacts	1.5			4.7			(0.2		)
Other adjustments	(4.2		)	3.1			(1.2		)
Remove PSIA from base rates	(14.2		)	(14.2		)	—
Recommendation	$	(15.3	)	$	1.2		$	29.2
Neutralize PSIA - base rate transfer	14.2			14.2			(14.2		)
Incremental base revenue	$	(1.1	)	$	15.4		$	15.0

Exceptions and corresponding responses are due to be filed in November 2013 and a CPUC decision is expected in December 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 FTY, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent.  

In October 2013, PSCo, the CPUC Staff, the OCC and Colorado Energy Consumers representing the Buildings Owners Management Association filed a comprehensive settlement which ties the outcome of the steam rate case to key issues to be decided in the natural gas rate case, including ROE and capital structure and allows the filed rates to be effective on Jan. 1, 2014, subject to refund for 60 days, resulting in a minimum 2014 annual rate increase of $1.2 million. The settlement withdraws the rate relief request for 2015 pending the outcome of the certificate of public convenience and necessity (CPCN) proceeding for the construction of the Sun Valley Steam Center. A decision on the settlement is expected at the end of 2013.

Annual Electric Earnings Test — An 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.  In June 2013, PSCo entered into a comprehensive settlement of issues with all parties associated with the 2012 earnings test, resulting in a refund obligation of approximately $8.2 million to be refunded through June 2014. As of Sept. 30, 2013, PSCo has also recognized management’s best estimate of an accrual for the 2013 test year.

Production Formula Rate ROE Complaint — On Aug. 30, 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates, which could reduce revenues approximately $2 million per year prospectively. The matter is currently pending the FERC’s action.

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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 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 Sept. 30, 2013 and 2012, PSCo credited the RESA regulatory asset balance $6.1 million and $6.2 million, respectively. The cumulative credit to the RESA regulatory asset balance was $99.4 million and $82.8 million at Sept. 30, 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. The CPUC is then expecting to review the framework and evidence regarding actual deliveries before determining to continue the sharing mechanism.

Electric Commodity Adjustment (ECA) / RESA Adjustment — In July 2013, PSCo advised the CPUC that it had inadvertently allocated purchased power expense between the deferred accounts for the ECA and the RESA from 2010 to 2012. In order to be in compliance with a series of CPUC orders, PSCo proposed to transfer from the RESA deferred account to the ECA deferred account approximately $26.2 million and to amortize the recovery of this amount over 12 months. The transfer, if approved, would mainly impact the timing of recovery. In addition, interest of $2.6 million was accrued on the amount related to the RESA. The PSCo application to change the ECA tariff to address this issue has been set for hearing in December 2013 by the CPUC.

ECA Prudence Review — In September 2013, the CPUC Staff requested that the 2012 annual ECA prudence review be set for hearing. The prudence review, as determined by the ALJ, will primarily consider if replacement power costs during the outage of jointly owned facilities were properly allocated between wholesale and retail customers. A hearing is expected in January 2014.

2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report. The OCC and CPUC Staff requested the CPUC set the matter for hearing to review in detail the information provided, including a review of the prudence of expenditures in 2012, and to develop standards for future filings. The CPUC approved the request on July 10, 2013 and assigned the matter to an ALJ.

Next steps in the procedural schedule are as follows:

• Direct testimony - Nov. 5, 2013;

• Intervenor testimony - Jan. 7, 2014;

• Rebuttal testimony - Feb. 6, 2014;

• Evidentiary hearing - March 3 - March 7, 2014;

• Initial brief - March 28, 2014; and

• Reply brief - April 11, 2014.

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.

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PSCo had approximately 1,441 megawatts (MW) and 1,433 MW of capacity under long-term purchased power agreements as of Sept. 30, 2013 and Dec. 31, 2012, respectively, with entities that have been determined to be variable interest entities.  PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  These agreements have expiration dates through the year 2028.

Environmental Contingencies

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard (NSPS) Proposal and Emission Guideline for Existing Sources — In September 2013, the U.S. Environmental Protection Agency (EPA) re-proposed a GHG NSPS for newly constructed power plants which seeks to establish carbon dioxide (CO₂) emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.

Federal Clean Water Act - Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. A final rule is anticipated in 2014. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on PSCo is uncertain at this time.

Regional Haze Rules — In 2005, the 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 $343.0 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 10^th 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.

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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

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.  In May 2013, the Fifth Circuit affirmed the district court’s dismissal of this lawsuit. Plaintiffs elected not to seek further review of this decision, which brings this litigation to a close.  No accrual was 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 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.

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In April 2013, the FERC issued an order on rehearing.   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 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 what claim Seattle has against PSCo prior to June 2000. In the proceeding, Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive. A FERC hearing on the issue is presently in progress. An ALJ initial decision is expected in December 2013.

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding 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 has been 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 Sept. 30, 2013		Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		0.3
Maximum amount outstanding	—		8
Weighted average interest rate, computed on a daily basis	N/A		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 Sept. 30, 2013		Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700	$	700
Amount outstanding at period end	—		154
Average amount outstanding	—		8
Maximum amount outstanding	—		165
Weighted average interest rate, computed on a daily basis	N/A		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 Sept. 30, 2013 and Dec. 31, 2012, there were $6.9 million and $4.0 million of letters of credit outstanding, respectively, under the credit facility.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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

At Sept. 30, 2013, PSCo had the following committed credit facility available (in millions of dollars): 

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	6.9	$	693.1

^(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 Sept. 30, 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.

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.

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

At Sept. 30, 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 Sept. 30, 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 and nine months ended Sept. 30, 2013 and 2012.

At Sept. 30, 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 Sept. 30, 2013 and Dec. 31, 2012:

(Amounts in Thousands)(a)(b)	Sept. 30, 2013	Dec. 31, 2012
Megawatt hours (MWh) of electricity	486	813
Million British thermal units (MMBtu) of natural gas	9,800	646
Gallons of vehicle fuel	239	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.

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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 Sept. 30, 2013, five of PSCo’s 10 most significant counterparties, comprising $43.2 million or 37 percent of this credit exposure at Sept. 30, 2013, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  The remaining five significant counterparties, comprising $46.5 million or 40 percent of this credit exposure at Sept. 30, 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 Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at July 1	$	(23,120	)	$	(18,865	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	11			(3,574		)
After-tax net realized gains on derivative transactions reclassified into earnings	(119		)	(304		)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(23,228	)	$	(22,743	)

	Nine Months Ended Sept. 30
(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 losses related to derivatives accounted for as hedges	(2		)	(9,311		)
After-tax net realized gains on derivative transactions reclassified into earnings	(355		)	(1,055		)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(23,228	)	$	(22,743	)

The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: 

	Three Months Ended Sept. 30, 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	$	—	$	—		$	(184	)	(a)	$	—	$	—
Vehicle fuel and other commodity	16		—			(11		)	(b)	—		—
Total	$	16	$	—		$	(195	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—	$	(1,727	)	$	—			$	—	$	13	(d)
Total	$	—	$	(1,727	)	$	—			$	—	$	13

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	Nine Months Ended Sept. 30, 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 Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(546	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(4		)	—			(30		)	(b)	—			—
Total	$	(4	)	$	—		$	(576	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—		$	(4,896	)	$	—			$	7	(e)	$	(216	)	(d)
Total	$	—		$	(4,896	)	$	—			$	7		$	(216	)

	Three Months Ended Sept. 30, 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 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	$	(5,836	)	$	—	$	(470	)	(a)	$	—	$	—
Vehicle fuel and other commodity	65			—		(20		)	(b)	—		—
Total	$	(5,771	)	$	—	$	(490	)		$	—	$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—	$	1	(c)
Natural gas commodity	—			1,109		—				—		—
Total	$	—		$	1,109	$	—			$	—	$	1

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

^(a)   Recorded to interest charges.

^(b)   Recorded to operating and maintenance (O&M) expenses.

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

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

^(e)   Amounts for the nine months ended Sept. 30, 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 nine months ended Sept. 30, 2013 were immaterial.  The remaining settlement losses for the nine months ended Sept. 30, 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.

PSCo had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 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 $2.7 million and $4.6 million gross liability position on the consolidated balance sheets at Sept. 30, 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 $2.7 million and $4.6 million at Sept. 30, 2013 and Dec. 31, 2012, respectively.  At Sept. 30, 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 Sept. 30, 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 Sept. 30, 2013:

	Sept. 30, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	33	$	—	$	33	$	—		$	33
Other derivative instruments:
Commodity trading	—		5,318		—		5,318		(2,507		)	2,811
Natural gas commodity	—		3,622		—		3,622		—			3,622
Total current derivative assets	$	—	$	8,973	$	—	$	8,973	$	(2,507	)	6,466
Purchased power agreements (a)												1,715
Current derivative instruments												$	8,181
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	12	$	—	$	12	$	—		$	12
Total noncurrent derivative assets	$	—	$	12	$	—	$	12	$	—		12
Purchased power agreements (a)												7,321
Noncurrent derivative instruments												$	7,333
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	—	$	4,844	$	—	$	4,844	$	(2,155	)	$	2,689
Total current derivative liabilities	$	—	$	4,844	$	—	$	4,844	$	(2,155	)	2,689
Purchased power agreements (a)												5,395
Current derivative instruments												$	8,084
Noncurrent derivative liabilities
Purchased power agreements (a)												24,663
Noncurrent derivative instruments												$	24,663

^(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 onthis 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 Sept. 30, 2013. At Sept. 30, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.4 million and no rights to reclaim cash collateral. 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
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	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 Dec. 31, 2012.  At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and no rights to reclaim cash collateral. 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 and nine months ended Sept. 30, 2013 and 2012.

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PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2013 and 2012.

Fair Value of Long-Term Debt

As of Sept. 30, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows: 

	Sept. 30, 2013				Dec. 31, 2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,874,022	$	4,059,661	$	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 Sept. 30, 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.  

9. Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012			2013			2012
Interest income	$	713		$	909		$	2,470		$	2,709
Other nonoperating income	667			441			2,186			1,807
Insurance policy expense	(434		)	(350		)	(811		)	(934		)
Other income, net	$	946		$	1,000		$	3,845		$	3,582

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.

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2013
Operating revenues from external customers	$	898,811	$	137,349	$	8,140	$	—		$	1,044,300
Intersegment revenues	67		3		—		(70		)	—
Total revenues	$	898,878	$	137,352	$	8,140	$	(70	)	$	1,044,300
Net income	$	158,498	$	3,555	$	4,213	$	—		$	166,266

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2013
Operating revenues from external customers	$	2,368,041	$	730,569	$	29,576	$	—		$	3,128,186
Intersegment revenues	215		75		—		(290		)	—
Total revenues	$	2,368,256	$	730,644	$	29,576	$	(290	)	$	3,128,186
Net income	$	322,569	$	46,141	$	11,460	$	—		$	380,170

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

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,302		$	5,679		$	803		$	706
Interest cost	11,540			12,776			5,934			6,131
Expected return on plan assets	(15,955		)	(16,326		)	(7,307		)	(6,264		)
Amortization of transition obligation	—			—			196			2,751
Amortization of prior service (credit) cost	(266		)	57			(1,229		)	(1,288		)
Amortization of net loss	10,855			8,552			3,490			2,734
Net periodic benefit cost	12,476			10,738			1,887			4,770
Additional cost recognized due to the effects of regulation	—			—			—			972
Net benefit cost recognized for financial reporting	$	12,476		$	10,738		$	1,887		$	5,742

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	Nine Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	18,905		$	17,039		$	2,409		$	2,119
Interest cost	34,620			38,329			17,802			18,395
Expected return on plan assets	(47,865		)	(48,977		)	(21,921		)	(18,792		)
Amortization of transition obligation	—			—			588			8,253
Amortization of prior service (credit) cost	(798		)	171			(3,687		)	(3,863		)
Amortization of net loss	32,563			25,652			10,469			8,198
Net periodic benefit cost	37,425			32,214			5,660			14,310
Additional cost recognized due to the effects of regulation	—			—			—			2,918
Net benefit cost recognized for financial reporting	$	37,425		$	32,214		$	5,660		$	17,228

In 2013, contributions of $192.2 million were made across four of Xcel Energy’s pension plans, of which $44.4 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 and nine months ended Sept. 30, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at July 1	$	(23,120	)
Other comprehensive gain before reclassifications	11
Gains reclassified from net accumulated other comprehensive loss	(119		)
Net current period other comprehensive loss	(108		)
Accumulated other comprehensive loss at Sept. 30	$	(23,228	)

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(22,871	)
Other comprehensive loss before reclassifications	(2		)
Gains reclassified from net accumulated other comprehensive loss	(355		)
Net current period other comprehensive loss	(357		)
Accumulated other comprehensive loss at Sept. 30	$	(23,228	)

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Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2013				Nine Months Ended Sept. 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(184	)	(a)	$	(546	)	(a)
Vehicle fuel derivatives	(11		)	(b)	(30		)	(b)
Total, pre-tax	(195		)		(576		)
Tax expense	76				221
Total amounts reclassified, net of tax	$	(119	)		$	(355	)

^(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; 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 Sept. 30, 2013.

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Results of Operations

PSCo’s net income was approximately $380.2 million for the nine months ended Sept. 30, 2013, compared with approximately $381.1 million for the same period in 2012.  The decrease is mainly due to higher O&M expenses, accruals for potential customer refunds associated with the 2013 earnings test, a 2012 tax benefit associated with federal subsidies for prescription drug plans and cooler summer weather. These factors were partially offset by electric rate increases, lower interest charges and cooler winter weather.

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:

	Nine Months Ended Sept. 30
(Millions of Dollars)	2013			2012
Electric revenues	$	2,368		$	2,268
Electric fuel and purchased power	(998		)	(921		)
Electric margin	$	1,370		$	1,347

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

Electric Revenues

(Millions of Dollars)	2013 vs. 2012
Fuel and purchased power cost recovery	$	76
Retail rate increases	31
Non-fuel riders	12
Demand side management (DSM) program revenue	10
Transmission revenue	7
Retail sales growth	3
PSCo earnings test refund obligation	(20		)
Estimated impact of weather	(16		)
DSM program incentives	(11		)
Other, net	8
Total increase in electric revenues	$	100

Electric Margin

(Millions of Dollars)	2013 vs. 2012
Retail rate increases	$	31
Non-fuel riders	12
DSM program revenue	10
Transmission revenue, net of costs	9
Retail sales growth	3
PSCo earnings test refund obligation	(20		)
Estimated impact of weather	(16		)
DSM program incentives	(11		)
Other, net	5
Total increase in electric margin	$	23

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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:

	Nine Months Ended Sept. 30
(Millions of Dollars)	2013			2012
Natural gas revenues	$	731		$	644
Cost of natural gas sold and transported	(403		)	(339		)
Natural gas margin	$	328		$	305

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

Natural Gas Revenues

(Millions of Dollars)	2013 vs. 2012
Purchased natural gas adjustment clause recovery	$	67
Estimated impact of weather	14
Retail rate increase	6
Retail sales growth	3
Other, net	(3		)
Total increase in natural gas revenues	$	87

Natural Gas Margin

(Millions of Dollars)	2013 vs. 2012
Estimated impact of weather	$	14
Retail rate increase	6
Retail sales growth	3
Total increase in natural gas margin	$	23

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased by $23.8 million, or 4.5 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2013 vs. 2012
Other electric and gas distribution expenses	$	19
Vegetation management costs	6
Transmission costs	4
Plant generation costs	2
Pipeline system integrity costs	(7		)
Employee benefits	(6		)
Other, net	6
Total increase in O&M expenses	$	24

DSM Program Expenses— DSM program expenses increased $11.6 million, or 12.6 percent, for the nine months ended Sept. 30, 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.

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Depreciation and Amortization— Depreciation and amortization expense increased by approximately $17.6 million, or 7.0 percent, for the nine months ended Sept. 30, 2013 compared with the same period for 2012.  The increase is primarily attributable to normal system expansion.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased by $4.8 million, or 4.8 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012.  The increase is primarily due to higher property taxes.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC)— AFUDC increased by $13.7 million for the nine months ended Sept. 30, 2013 compared with the same period in 2012.  The increase is primarily due to construction related to the CACJA.

Interest Charges —Interest charges decreased by $17.9 million, or 12.3 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012.  The decrease is primarily due to refinancings at lower interest rates, partially offset by higher long-term debt levels.

Income Taxes — Income tax expense increased $21.9 million for the nine months ended Sept. 30, 2013 compared with the same period in 2012.  The increase in income tax expense was primarily due to higher pretax earnings in 2013 and a tax benefit recorded in 2012 related to the restoration of a portion of a tax benefit written off in 2010 associated with federal subsidies for prescription drug plans.  The ETR was 35.8 percent for the nine months ended Sept. 30, 2013 compared with 33.2 percent for the same period in 2012. The ETR would have been 36.2 percent for the nine months ended Sept. 30, 2012 without the 2012 tax benefit.

Public Utility Regulation

Colorado 2011 Electric Resource Plan (ERP) and 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. PSCo also issued a separate wind RFP for PPAs only.

In September 2013, PSCo filed its preferred plan with the CPUC for resources through 2018, which included the following:

• The addition of 450 MW of Colorado wind generation PPAs. This additional wind would bring the installed capacity on the PSCo’s system in Colorado to 2,650 MW;

• The addition of 170 MW of utility-scale solar generation PPAs. PSCo currently has about 80 MW of utility-scale solar and 160 MW of customer-sited solar generation;

• The addition of 317 MW of natural gas fired generation PPAs, which would come from existing Colorado power plants that previously supplied PSCo, but at reduced prices.

• PSCo also examined whether to continue operating two older company-owned power plants or to replace them with new generation resources. PSCo recommended:

◦ The permanent closure of the 109 MW, coal-fired Unit 4 at the Arapahoe Generating Station in Denver at the end of 2013;

◦ The permanent closure of the 45 MW, coal-fired Unit 3 at the Arapahoe Generating Station in Denver at the end of 2013; and

◦ The continued operation of Cherokee Generating Station’s Unit 4 in Denver as a natural gas facility after 2017 (the plant fuel source will be switched to natural gas from coal by the end of 2017 as part of the CACJA Plan).

In October 2013, the CPUC approved the proposed wind PPAs, citing the significant benefit to customers of acquiring these renewable resources. The CPUC will consider the remaining recommendations later this fall with a decision expected before the end of 2013.

Boulder, Colo. Municipalization Exploration— PSCo’s franchise agreement with the City of Boulder expired on Dec. 31, 2010. In November 2010, the citizens of Boulder voted to impose an occupational tax to replace franchise fee revenues that would terminate when the franchise agreement terminated. 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.

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Boulder Staff have performed a feasibility study on municipalization and in July 2013, recommended that Boulder create its own electric utility. A Task Force of Boulder citizens met with PSCo and City representatives from April through July and recommended continued discussions between Boulder and Xcel Energy. In August 2013, the Boulder City Council voted to authorize the acquisition of PSCo’s transmission and distribution system in and near Boulder on or after Jan. 1, 2014. The City Council also directed City Staff to continue discussions with PSCo through the citizen Task Force on PSCo proposals to meet the City’s energy future goals.

Boulder’s feasibility study assumes that Boulder will acquire through condemnation PSCo facilities (and customers currently served from these PSCo facilities) that are located outside Boulder’s incorporated limits. PSCo has petitioned the CPUC for a declaratory ruling that Boulder cannot serve PSCo’s customers outside Boulder’s city limits without obtaining a CPCN from the CPUC. In oral deliberations on Oct. 9, 2013, the CPUC declared that the CPUC has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine what facilities need to be constructed to ensure reliable service. The CPUC stated it believes that the cost of all new facilities must be paid by Boulder. The CPUC declared that it should make its determinations prior to any eminent domain actions. A written order is expected in the fourth quarter of 2013.

Boulder filed a petition with the FERC for a declaratory ruling that if Boulder enters into a partial requirements wholesale contract with PSCo, no stranded costs associated with the MW supplied under the partial requirements contract would be owed by Boulder. In July 2013, the FERC denied Boulder’s petition, without prejudice.

There are two measures on the November ballot that could affect Boulder’s municipalization options. A citizen petitioned measure would require, among other things, voter approval of the total debt issued by Boulder in connection with its municipal utility. A City Council referred measure would limit facility acquisition cost to $214 million.

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

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 in July 2011 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 regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region.  In addition, 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. Colorado does not have legislation protecting ROFR rights for incumbent utilities.

PSCo is not in a regional transmission organization and therefore is responsible for making its own Order 1000 compliance filing. PSCo submitted its compliance filing to address the regional planning and cost allocation requirements of Order 1000, proposing that PSCo would join the WestConnect region, 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.  In April 2013, PSCo and other WestConnect members requested rehearing on various aspects of the March 2013 order. While requests for rehearing of the March 2013 order are pending, PSCo and other WestConnect jurisdictional utilities made their compliance filings on Sept. 20, 2013 to address directives in the March 2013 order. The FERC is expected to rule in late 2013 or early 2014 on the compliance filing and the requests for rehearing that were filed. The WestConnect members filed the interregional compliance filing in May 2013 and action on that filing is pending.

29

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of Sept. 30, 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.

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.

30

Item 6 — EXHIBITS

* Indicates incorporation by reference

3.01*	Amended and Restated Articles of Incorporation dated July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02	By-Laws of PSCo as Amended and Restated on Sept. 26, 2013.
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from PSCo’s Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 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.

31

SIGNATURES

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

		Public Service Company of Colorado
Oct. 28, 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

32

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: Oct. 28, 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: Oct. 28, 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 Sept. 30, 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: Oct. 28, 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.

XML

Fair Value of Financial Assets and Liabilities

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

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 Sept. 30, 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 Sept. 30, 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 and nine months ended Sept. 30, 2013 and 2012.

At Sept. 30, 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 Sept. 30, 2013 and Dec. 31, 2012:

(Amounts in Thousands)(a)(b)	Sept. 30, 2013	Dec. 31, 2012
Megawatt hours (MWh) of electricity	486	813
Million British thermal units (MMBtu) of natural gas	9,800	646
Gallons of vehicle fuel	239	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 Sept. 30, 2013, five of PSCo’s 10 most significant counterparties, comprising $43.2 million or 37 percent of this credit exposure at Sept. 30, 2013, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  The remaining five significant counterparties, comprising $46.5 million or 40 percent of this credit exposure at Sept. 30, 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 Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at July 1	$	(23,120	)	$	(18,865	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	11			(3,574		)
After-tax net realized gains on derivative transactions reclassified into earnings	(119		)	(304		)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(23,228	)	$	(22,743	)

	Nine Months Ended Sept. 30
(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 losses related to derivatives accounted for as hedges	(2		)	(9,311		)
After-tax net realized gains on derivative transactions reclassified into earnings	(355		)	(1,055		)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(23,228	)	$	(22,743	)

The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: 

	Three Months Ended Sept. 30, 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	$	—	$	—		$	(184	)	(a)	$	—	$	—
Vehicle fuel and other commodity	16		—			(11		)	(b)	—		—
Total	$	16	$	—		$	(195	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—	$	(1,727	)	$	—			$	—	$	13	(d)
Total	$	—	$	(1,727	)	$	—			$	—	$	13

	Nine Months Ended Sept. 30, 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 Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(546	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(4		)	—			(30		)	(b)	—			—
Total	$	(4	)	$	—		$	(576	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—		$	(4,896	)	$	—			$	7	(e)	$	(216	)	(d)
Total	$	—		$	(4,896	)	$	—			$	7		$	(216	)

	Three Months Ended Sept. 30, 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 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	$	(5,836	)	$	—	$	(470	)	(a)	$	—	$	—
Vehicle fuel and other commodity	65			—		(20		)	(b)	—		—
Total	$	(5,771	)	$	—	$	(490	)		$	—	$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—	$	1	(c)
Natural gas commodity	—			1,109		—				—		—
Total	$	—		$	1,109	$	—			$	—	$	1

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

^(a)   Recorded to interest charges.

^(b)   Recorded to operating and maintenance (O&M) expenses.

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

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

^(e)   Amounts for the nine months ended Sept. 30, 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 nine months ended Sept. 30, 2013 were immaterial.  The remaining settlement losses for the nine months ended Sept. 30, 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.

PSCo had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 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 $2.7 million and $4.6 million gross liability position on the consolidated balance sheets at Sept. 30, 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 $2.7 million and $4.6 million at Sept. 30, 2013 and Dec. 31, 2012, respectively.  At Sept. 30, 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 Sept. 30, 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 Sept. 30, 2013:

	Sept. 30, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	33	$	—	$	33	$	—		$	33
Other derivative instruments:
Commodity trading	—		5,318		—		5,318		(2,507		)	2,811
Natural gas commodity	—		3,622		—		3,622		—			3,622
Total current derivative assets	$	—	$	8,973	$	—	$	8,973	$	(2,507	)	6,466
Purchased power agreements (a)												1,715
Current derivative instruments												$	8,181
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	12	$	—	$	12	$	—		$	12
Total noncurrent derivative assets	$	—	$	12	$	—	$	12	$	—		12
Purchased power agreements (a)												7,321
Noncurrent derivative instruments												$	7,333
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	—	$	4,844	$	—	$	4,844	$	(2,155	)	$	2,689
Total current derivative liabilities	$	—	$	4,844	$	—	$	4,844	$	(2,155	)	2,689
Purchased power agreements (a)												5,395
Current derivative instruments												$	8,084
Noncurrent derivative liabilities
Purchased power agreements (a)												24,663
Noncurrent derivative instruments												$	24,663

^(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 onthis 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 Sept. 30, 2013. At Sept. 30, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.4 million and no rights to reclaim cash collateral. 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
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	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 Dec. 31, 2012.  At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and no rights to reclaim cash collateral. 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 and nine months ended Sept. 30, 2013 and 2012.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2013 and 2012.

Fair Value of Long-Term Debt

As of Sept. 30, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows: 

	Sept. 30, 2013				Dec. 31, 2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,874,022	$	4,059,661	$	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 Sept. 30, 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.

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Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012	Sep. 30, 2013		Sep. 30, 2012
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period				$ (22,871)
Accumulated other comprehensive loss at end of period	(23,228)			(23,228)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	43,187		49,369	127,806		145,734
Operating and maintenance expenses	192,073		180,994	553,266		529,476
Total, pre-tax	(259,502)		(274,342)	(591,721)		(570,744)
Tax expense	93,236		81,899	211,551		189,609
Gains and Losses on Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(23,120)			(22,871)
Other comprehensive gain (loss) before reclassifications	11			(2)
Gains reclassified from net accumulated other comprehensive loss	(119)			(355)
Net current period other comprehensive income (loss)	(108)			(357)
Accumulated other comprehensive loss at end of period	(23,228)			(23,228)
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	(195)			(576)
Tax expense	76			221
Total, net of tax	(119)			(355)
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	(184)	[1]		(546)	[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	$ (11)	[2]		$ (30)	[2]

[1] Included in interest charges.

[2] Included in O&M expenses

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Comprehensive income:
Net income	$ 166,266	$ 192,443	$ 380,170	$ 381,135
Derivative instruments:
Net fair value increase (decrease), net of tax of $5, $(2,197), $(2), and $(5,710), respectively	11	(3,574)	(2)	(9,311)
Reclassification of gains to net income, net of tax of $(76), $(186), $(221), and $(646), respectively	(119)	(304)	(355)	(1,055)
Other comprehensive loss	(108)	(3,878)	(357)	(10,366)
Comprehensive income	$ 166,158	$ 188,565	$ 379,813	$ 370,769

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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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Rate Matters (Tables)

9 Months Ended

Sep. 30, 2013

Public Utilities, General Disclosures [Abstract]

CPUC Staff, OCC and ALJ’s recommendations in the PSCo Colorado 2013 Gas Rate Case [Table Text Block]

The following table summarizes the CPUC Staff, OCC and ALJ's recommendations:

(Millions of Dollars)	CPUC Staff			OCC			ALJ
PSCo deficiency based on a FTY	$	44.8		$	44.8		$	44.8
Move to HTY	(1.6		)	(1.6		)	(1.6		)
ROE and capital structure adjustments	(20.8		)	(20.0		)	(7.7		)
Move to a 13 month average from year end rate base	(5.7		)	(3.2		)	(3.3		)
Remove pension asset	(5.9		)	—			—
Reduce pension expense net of corrections	(1.6		)	—			—
Remove incentive compensation	(3.5		)	(0.2		)	(0.2		)
Challenge known and measurable	—			(9.0		)	—
Eliminate depreciation annualization	—			(1.8		)	—
Revenue adjustments	(4.1		)	(1.4		)	(1.4		)
Resulting tax impacts	1.5			4.7			(0.2		)
Other adjustments	(4.2		)	3.1			(1.2		)
Remove PSIA from base rates	(14.2		)	(14.2		)	—
Recommendation	$	(15.3	)	$	1.2		$	29.2
Neutralize PSIA - base rate transfer	14.2			14.2			(14.2		)
Incremental base revenue	$	(1.1	)	$	15.4		$	15.0

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Other Income, Net

9 Months Ended

Sep. 30, 2013

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012			2013			2012
Interest income	$	713		$	909		$	2,470		$	2,709
Other nonoperating income	667			441			2,186			1,807
Insurance policy expense	(434		)	(350		)	(811		)	(934		)
Other income, net	$	946		$	1,000		$	3,845		$	3,582

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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		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 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	$ 0	$ 0
Transfers out of Level 3	$ 0	$ 0	$ 0	$ 0

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Commitments and Contingencies, Legal Contingencies (Details) (USD $)	3 Months Ended		9 Months Ended				9 Months Ended	13 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Comer vs. Xcel Energy Inc. et al. [Member]	May 31, 2011 Comer vs. Xcel Energy Inc. et al. [Member] Counterparty	Sep. 30, 2013 Pacific Northwest FERC Refund Proceeding [Member] Factor	Jun. 30, 2001 Pacific Northwest FERC Refund Proceeding [Member]
Legal Contingencies [Abstract]
Accrual for legal contingency					$ 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	1,044,300,000	992,287,000	3,128,186,000	2,937,840,000				50,000,000
Estimated City of Seattle's claim for refunds not including interest							$ 28,000,000
Number of factors considered in assessment							2

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Other Income, Net (Tables)

9 Months Ended

Sep. 30, 2013

Other Income and Expenses [Abstract]

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2013			2012			2013			2012
Interest income	$	713		$	909		$	2,470		$	2,709
Other nonoperating income	667			441			2,186			1,807
Insurance policy expense	(434		)	(350		)	(811		)	(934		)
Other income, net	$	946		$	1,000		$	3,845		$	3,582

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Fair Value of Financial Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

The following table details the gross notional amounts of commodity forwards and options at Sept. 30, 2013 and Dec. 31, 2012:

(Amounts in Thousands)(a)(b)	Sept. 30, 2013	Dec. 31, 2012
Megawatt hours (MWh) of electricity	486	813
Million British thermal units (MMBtu) of natural gas	9,800	646
Gallons of vehicle fuel	239	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 Sept. 30
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at July 1	$	(23,120	)	$	(18,865	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	11			(3,574		)
After-tax net realized gains on derivative transactions reclassified into earnings	(119		)	(304		)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(23,228	)	$	(22,743	)

	Nine Months Ended Sept. 30
(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 losses related to derivatives accounted for as hedges	(2		)	(9,311		)
After-tax net realized gains on derivative transactions reclassified into earnings	(355		)	(1,055		)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(23,228	)	$	(22,743	)

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 and nine months ended Sept. 30, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: 

	Three Months Ended Sept. 30, 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	$	—	$	—		$	(184	)	(a)	$	—	$	—
Vehicle fuel and other commodity	16		—			(11		)	(b)	—		—
Total	$	16	$	—		$	(195	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—	$	(1,727	)	$	—			$	—	$	13	(d)
Total	$	—	$	(1,727	)	$	—			$	—	$	13

	Nine Months Ended Sept. 30, 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 Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(546	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(4		)	—			(30		)	(b)	—			—
Total	$	(4	)	$	—		$	(576	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—		$	(4,896	)	$	—			$	7	(e)	$	(216	)	(d)
Total	$	—		$	(4,896	)	$	—			$	7		$	(216	)

	Three Months Ended Sept. 30, 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 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	$	(5,836	)	$	—	$	(470	)	(a)	$	—	$	—
Vehicle fuel and other commodity	65			—		(20		)	(b)	—		—
Total	$	(5,771	)	$	—	$	(490	)		$	—	$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—	$	1	(c)
Natural gas commodity	—			1,109		—				—		—
Total	$	—		$	1,109	$	—			$	—	$	1

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

^(a)   Recorded to interest charges.

^(b)   Recorded to operating and maintenance (O&M) expenses.

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

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

^(e)   Amounts for the nine months ended Sept. 30, 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 nine months ended Sept. 30, 2013 were immaterial.  The remaining settlement losses for the nine months ended Sept. 30, 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.

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 Sept. 30, 2013:

	Sept. 30, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	33	$	—	$	33	$	—		$	33
Other derivative instruments:
Commodity trading	—		5,318		—		5,318		(2,507		)	2,811
Natural gas commodity	—		3,622		—		3,622		—			3,622
Total current derivative assets	$	—	$	8,973	$	—	$	8,973	$	(2,507	)	6,466
Purchased power agreements (a)												1,715
Current derivative instruments												$	8,181
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	12	$	—	$	12	$	—		$	12
Total noncurrent derivative assets	$	—	$	12	$	—	$	12	$	—		12
Purchased power agreements (a)												7,321
Noncurrent derivative instruments												$	7,333
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	—	$	4,844	$	—	$	4,844	$	(2,155	)	$	2,689
Total current derivative liabilities	$	—	$	4,844	$	—	$	4,844	$	(2,155	)	2,689
Purchased power agreements (a)												5,395
Current derivative instruments												$	8,084
Noncurrent derivative liabilities
Purchased power agreements (a)												24,663
Noncurrent derivative instruments												$	24,663

^(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 onthis 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 Sept. 30, 2013. At Sept. 30, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.4 million and no rights to reclaim cash collateral. 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
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	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 Dec. 31, 2012.  At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and no rights to reclaim cash collateral. 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 Sept. 30, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows: 

	Sept. 30, 2013				Dec. 31, 2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,874,022	$	4,059,661	$	3,630,773	$	4,131,866

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Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 2,700,000	$ 4,600,000
Payments required if credit ratings were downgraded below investment grade	2,700,000	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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Income Taxes (Details) (USD $)			3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012 Internal Revenue Service (IRS)	Sep. 30, 2013 Internal Revenue Service (IRS)	Dec. 31, 2012 State Jurisdiction (Colorado)	Sep. 30, 2013 State Jurisdiction (Colorado)
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	$ 2,400,000	$ 1,300,000
Unrecognized tax benefit — Temporary tax positions	9,400,000	8,300,000
Total unrecognized tax benefit	11,800,000	9,600,000
NOL and tax credit carryforwards	(7,800,000)	(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, Letters of Credit (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Letters of Credit [Abstract]
Terms of letters of credit (in years)	1 year
Letters of credit outstanding under credit facilities	$ 6.9	$ 4.0

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 3,874,022	$ 3,630,773
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,059,661	$ 4,131,866

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Selected Balance Sheet Data (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$ 305,360	$ 299,379
Less allowance for bad debts	(22,537)	(21,918)
Accounts receivable, net	$ 282,823	$ 277,461

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 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]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	$ 43.2
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	37.00%
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	5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	46.5
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	40.00%
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	486,000	[1],[2]	813,000	[1],[2]
Natural Gas Commodity [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	9,800,000	[1],[2]	646,000	[1],[2]
Vehicle Fuel Commodity [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	239,000	[1],[2]	307,000	[1],[2]

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

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

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Borrowings and Other Financing Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Borrowings and Other Financing Instruments [Abstract]

Committed Credit Facility Available

At Sept. 30, 2013, PSCo had the following committed credit facility available (in millions of dollars): 

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	6.9	$	693.1

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding letters of credit.

Money Pool

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 Sept. 30, 2013		Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		0.3
Maximum amount outstanding	—		8
Weighted average interest rate, computed on a daily basis	N/A		0.33		%
Weighted average interest rate at period end	N/A		N/A

Commercial Paper

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 Sept. 30, 2013		Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700	$	700
Amount outstanding at period end	—		154
Average amount outstanding	—		8
Maximum amount outstanding	—		165
Weighted average interest rate, computed on a daily basis	N/A		0.33		%
Weighted average interest rate at period end	N/A		0.35

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Operating activities
Net income	$ 380,170	$ 381,135
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	271,150	253,764
Demand side management program amortization	3,658	4,042
Deferred income taxes	230,665	179,254
Amortization of investment tax credits	(2,219)	(1,955)
Allowance for equity funds used during construction	(21,529)	(10,961)
Net realized and unrealized hedging and derivative transactions	(9,052)	(39,241)
Changes in operating assets and liabilities:
Accounts receivable	61,660	50,612
Accrued unbilled revenues	80,347	110,880
Inventories	(28,021)	11,553
Prepayments and other	5,818	(33,967)
Accounts payable	(28,581)	(83,400)
Net regulatory assets and liabilities	74,709	(66,007)
Other current liabilities	(16,662)	(8,444)
Pension and other employee benefit obligations	(44,101)	(59,154)
Change in other noncurrent assets	6,917	(8,730)
Change in other noncurrent liabilities	7,744	(505)
Net cash provided by operating activities	972,673	678,876
Investing activities
Utility capital/construction expenditures	(742,822)	(610,309)
Allowance for equity funds used during construction	21,529	10,961
Investments in utility money pool arrangement	(1,086,000)	(820,000)
Repayments from utility money pool arrangement	951,000	752,000
Net cash used in investing activities	(856,293)	(667,348)
Financing activities
Repayments of short-term borrowings, net	(154,000)	0
Borrowings under utility money pool arrangement	14,000	36,000
Repayments under utility money pool arrangement	(14,000)	(36,000)
Proceeds from issuance of long-term debt	492,372	791,007
Repayments of long-term debt	(250,000)	0
Capital contributions from parent	4,485	28,122
Dividends paid to parent	(198,941)	(200,501)
Net cash (used in) provided by financing activities	(106,084)	618,628
Net change in cash and cash equivalents	10,296	630,156
Cash and cash equivalents at beginning of period	5,150	3,763
Cash and cash equivalents at end of period	15,446	633,919
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(131,378)	(133,667)
Cash received (paid) for income taxes, net	41,531	(51,240)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 100,475	$ 79,597

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Sep. 30, 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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Accounting Pronouncements

9 Months Ended

Sep. 30, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

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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Management's Opinion

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [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 Sept. 30, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2013 and 2012; and its cash flows for the nine months ended Sept. 30, 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 Sept. 30, 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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Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
Credit Facility [Abstract]
Credit facility	$ 700,000,000	[1]
Drawn	6,900,000	[2]
Available	693,100,000
Credit facility bank borrowings outstanding	$ 0		$ 0

[1] Credit facility expires in July 2017.

[2] Includes outstanding letters of credit.

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Results from Continuing Operations by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2013
Operating revenues from external customers	$	898,811	$	137,349	$	8,140	$	—		$	1,044,300
Intersegment revenues	67		3		—		(70		)	—
Total revenues	$	898,878	$	137,352	$	8,140	$	(70	)	$	1,044,300
Net income	$	158,498	$	3,555	$	4,213	$	—		$	166,266

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2013
Operating revenues from external customers	$	2,368,041	$	730,569	$	29,576	$	—		$	3,128,186
Intersegment revenues	215		75		—		(290		)	—
Total revenues	$	2,368,256	$	730,644	$	29,576	$	(290	)	$	3,128,186
Net income	$	322,569	$	46,141	$	11,460	$	—		$	380,170

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

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Public Utilities, Inventory [Line Items]
Inventories	$ 251,234	$ 223,794
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	55,869	54,486
Fuel
Public Utilities, Inventory [Line Items]
Inventories	86,597	89,246
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 108,768	$ 80,062

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Commitments and Contingencies, Environmental Contingencies (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013 Federal Clean Water Act Regulation	Dec. 31, 2010 Regional Haze Rules Boiler Kiln Group	Sep. 30, 2013 Capital Addition Purchase Commitments Regional Haze Rules
Environmental Requirements [Abstract]
Number of potential regulatory options under the proposed Effluent Limitations Guidelines rule	4
Liability for estimated cost to comply with regulation			$ 343.0
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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Other Income, Net (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other Income and Expenses [Abstract]
Interest income	$ 713	$ 909	$ 2,470	$ 2,709
Other nonoperating income	667	441	2,186	1,807
Insurance policy expense	(434)	(350)	(811)	(934)
Other income, net	$ 946	$ 1,000	$ 3,845	$ 3,582

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0		$ 0		$ 0		$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0		0		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	16,000		(5,771,000)		(4,000)		(15,021,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(195,000)		(490,000)		(576,000)		(1,701,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		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		(5,836,000)		0		(15,082,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(184,000)	[1]	(470,000)	[1]	(546,000)	[1]	(1,635,000)	[1]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		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	16,000		65,000		(4,000)		61,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(11,000)	[2]	(20,000)	[2]	(30,000)	[2]	(66,000)	[2]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		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		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	(1,727,000)		1,109,000		(4,896,000)		(5,837,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		7,000		61,858,000
Pre-tax gains (losses) recognized during the period in income	13,000		1,000		(216,000)		(107,000)
Other Derivative Instruments [Member] | Commodity Trading [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			0				0
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)			0				0
Pre-tax gains (losses) recognized during the period in income			1,000	[3]			2,000	[3]
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 fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	(1,727,000)		1,109,000		(4,896,000)		(5,837,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		7,000	[4]	61,858,000	[4]
Pre-tax gains (losses) recognized during the period in income	13,000	[5]	0		(216,000)	[5]	(109,000)
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 (gains) losses reclassified into income during the period from regulatory assets and (liabilities)							$ (5,000,000)

[1] Recorded to interest charges.

[2] Recorded to operating and maintenance (O&M) expenses.

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

[4] Amounts for the nine months ended Sept. 30, 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 nine months ended Sept. 30, 2013 were immaterial. The remaining settlement losses for the nine months ended Sept. 30, 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.

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

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Interest charges and financing costs
Other financing costs	$ 1,747	$ 1,803	$ 5,118	$ 5,383

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Rate Matters

9 Months Ended

Sep. 30, 2013

Public Utilities, General Disclosures [Abstract]

Rate Matters

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 and in Note 5 to PSCo’s Quarterly Reports on Form 10-Q for the quarter periods ended March 31, 2013 and June 30, 2013, 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

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 (FTY), 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. Interim rates, subject to refund, went into effect in August 2013.

In April 2013, four parties filed answer testimony in the natural gas case.  The CPUC Staff recommended an incremental base revenue decrease of $1.1 million, based on a historic test year (HTY), an ROE of 9 percent and an equity ratio of 52 percent.  The Office of Consumer Counsel (OCC) recommended an incremental base revenue increase of $15.4 million based on an HTY, an ROE of 9 percent and an equity ratio of 51.03 percent and other adjustments. The recommended incremental base revenues are inclusive of proposed changes to the level of integrity management costs moved from the PSIA rider to base rates. 

In April 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, with subsequent step increases of $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. This requested increase includes amounts to be transferred from the PSIA rider mechanism. The deficiency, based on an FTY, was $30.6 million.

In October 2013, the administrative law judge (ALJ) issued her recommendation. As part of this decision, she recommended the use of an HTY, an ROE of 9.72 percent and an equity ratio of 56 percent. The ALJ also recommended to reject PSCo's proposed changes to the PSIA, instead leaving the current rider in effect and suggested that changes be presented in a separate application. The recommended incremental base revenue increase was approximately $15.0 million.

The following table summarizes the CPUC Staff, OCC and ALJ's recommendations:

(Millions of Dollars)	CPUC Staff			OCC			ALJ
PSCo deficiency based on a FTY	$	44.8		$	44.8		$	44.8
Move to HTY	(1.6		)	(1.6		)	(1.6		)
ROE and capital structure adjustments	(20.8		)	(20.0		)	(7.7		)
Move to a 13 month average from year end rate base	(5.7		)	(3.2		)	(3.3		)
Remove pension asset	(5.9		)	—			—
Reduce pension expense net of corrections	(1.6		)	—			—
Remove incentive compensation	(3.5		)	(0.2		)	(0.2		)
Challenge known and measurable	—			(9.0		)	—
Eliminate depreciation annualization	—			(1.8		)	—
Revenue adjustments	(4.1		)	(1.4		)	(1.4		)
Resulting tax impacts	1.5			4.7			(0.2		)
Other adjustments	(4.2		)	3.1			(1.2		)
Remove PSIA from base rates	(14.2		)	(14.2		)	—
Recommendation	$	(15.3	)	$	1.2		$	29.2
Neutralize PSIA - base rate transfer	14.2			14.2			(14.2		)
Incremental base revenue	$	(1.1	)	$	15.4		$	15.0

Exceptions and corresponding responses are due to be filed in November 2013 and a CPUC decision is expected in December 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 FTY, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent.  

In October 2013, PSCo, the CPUC Staff, the OCC and Colorado Energy Consumers representing the Buildings Owners Management Association filed a comprehensive settlement which ties the outcome of the steam rate case to key issues to be decided in the natural gas rate case, including ROE and capital structure and allows the filed rates to be effective on Jan. 1, 2014, subject to refund for 60 days, resulting in a minimum 2014 annual rate increase of $1.2 million. The settlement withdraws the rate relief request for 2015 pending the outcome of the certificate of public convenience and necessity (CPCN) proceeding for the construction of the Sun Valley Steam Center. A decision on the settlement is expected at the end of 2013.

Annual Electric Earnings Test — An 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.  In June 2013, PSCo entered into a comprehensive settlement of issues with all parties associated with the 2012 earnings test, resulting in a refund obligation of approximately $8.2 million to be refunded through June 2014. As of Sept. 30, 2013, PSCo has also recognized management’s best estimate of an accrual for the 2013 test year.

Production Formula Rate ROE Complaint — On Aug. 30, 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates, which could reduce revenues approximately $2 million per year prospectively. The matter is currently pending the FERC’s action.

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 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 Sept. 30, 2013 and 2012, PSCo credited the RESA regulatory asset balance $6.1 million and $6.2 million, respectively. The cumulative credit to the RESA regulatory asset balance was $99.4 million and $82.8 million at Sept. 30, 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. The CPUC is then expecting to review the framework and evidence regarding actual deliveries before determining to continue the sharing mechanism.

Electric Commodity Adjustment (ECA) / RESA Adjustment — In July 2013, PSCo advised the CPUC that it had inadvertently allocated purchased power expense between the deferred accounts for the ECA and the RESA from 2010 to 2012. In order to be in compliance with a series of CPUC orders, PSCo proposed to transfer from the RESA deferred account to the ECA deferred account approximately $26.2 million and to amortize the recovery of this amount over 12 months. The transfer, if approved, would mainly impact the timing of recovery. In addition, interest of $2.6 million was accrued on the amount related to the RESA. The PSCo application to change the ECA tariff to address this issue has been set for hearing in December 2013 by the CPUC.

ECA Prudence Review — In September 2013, the CPUC Staff requested that the 2012 annual ECA prudence review be set for hearing. The prudence review, as determined by the ALJ, will primarily consider if replacement power costs during the outage of jointly owned facilities were properly allocated between wholesale and retail customers. A hearing is expected in January 2014.

2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report. The OCC and CPUC Staff requested the CPUC set the matter for hearing to review in detail the information provided, including a review of the prudence of expenditures in 2012, and to develop standards for future filings. The CPUC approved the request on July 10, 2013 and assigned the matter to an ALJ.

Next steps in the procedural schedule are as follows:

• Direct testimony - Nov. 5, 2013;

• Intervenor testimony - Jan. 7, 2014;

• Rebuttal testimony - Feb. 6, 2014;

• Evidentiary hearing - March 3 - March 7, 2014;

• Initial brief - March 28, 2014; and

• Reply brief - April 11, 2014.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative instruments:
Net fair value increase (decrease), tax	$ 5	$ (2,197)	$ (2)	$ (5,710)
Reclassification of gains to net income, tax	$ (76)	$ (186)	$ (221)	$ (646)

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating revenues
Electric	$ 898,811	$ 870,975	$ 2,368,041	$ 2,267,905
Natural gas	137,349	113,230	730,569	643,632
Steam and other	8,140	8,082	29,576	26,303
Total operating revenues	1,044,300	992,287	3,128,186	2,937,840
Operating expenses
Electric fuel and purchased power	355,727	315,319	998,395	920,916
Cost of natural gas sold and transported	43,881	24,662	403,198	338,630
Cost of sales — steam and other	3,398	3,650	12,211	10,745
Operating and maintenance expenses	192,073	180,994	553,266	529,476
Demand side management program expenses	38,016	33,670	104,075	92,462
Depreciation and amortization	88,577	85,905	267,206	249,645
Taxes (other than income taxes)	32,887	32,696	104,120	99,359
Total operating expenses	754,559	676,896	2,442,471	2,241,233
Operating income	289,741	315,391	685,715	696,607
Other income, net	946	1,000	3,845	3,582
Allowance for funds used during construction — equity	8,815	4,687	21,529	10,961
Interest charges and financing costs
Interest charges — includes other financing costs of $1,747, $1,803, $5,118 and $5,383, respectively	43,187	49,369	127,806	145,734
Allowance for funds used during construction — debt	(3,187)	(2,633)	(8,438)	(5,328)
Total interest charges and financing costs	40,000	46,736	119,368	140,406
Income before income taxes	259,502	274,342	591,721	570,744
Income taxes	93,236	81,899	211,551	189,609
Net income	$ 166,266	$ 192,443	$ 380,170	$ 381,135

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Segment Reporting Information [Line Items]
Operating revenues	$ 1,044,300	$ 992,287	$ 3,128,186	$ 2,937,840
Net income	166,266	192,443	380,170	381,135
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	898,878	871,038	2,368,256	2,268,103
Net income	158,498	181,743	322,569	331,883
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	137,352	113,211	730,644	643,687
Net income	3,555	6,366	46,141	40,205
All Other
Segment Reporting Information [Line Items]
Operating revenues	8,140	8,082	29,576	26,303
Net income	4,213	4,334	11,460	9,047
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,044,300	992,287	3,128,186	2,937,840
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	898,811	870,975	2,368,041	2,267,905
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	137,349	113,230	730,569	643,632
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	8,140	8,082	29,576	26,303
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(70)	(44)	(290)	(253)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	67	63	215	198
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	3	(19)	75	55
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0	$ 0	$ 0	$ 0

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Benefit Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,302		$	5,679		$	803		$	706
Interest cost	11,540			12,776			5,934			6,131
Expected return on plan assets	(15,955		)	(16,326		)	(7,307		)	(6,264		)
Amortization of transition obligation	—			—			196			2,751
Amortization of prior service (credit) cost	(266		)	57			(1,229		)	(1,288		)
Amortization of net loss	10,855			8,552			3,490			2,734
Net periodic benefit cost	12,476			10,738			1,887			4,770
Additional cost recognized due to the effects of regulation	—			—			—			972
Net benefit cost recognized for financial reporting	$	12,476		$	10,738		$	1,887		$	5,742

	Nine Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	18,905		$	17,039		$	2,409		$	2,119
Interest cost	34,620			38,329			17,802			18,395
Expected return on plan assets	(47,865		)	(48,977		)	(21,921		)	(18,792		)
Amortization of transition obligation	—			—			588			8,253
Amortization of prior service (credit) cost	(798		)	171			(3,687		)	(3,863		)
Amortization of net loss	32,563			25,652			10,469			8,198
Net periodic benefit cost	37,425			32,214			5,660			14,310
Additional cost recognized due to the effects of regulation	—			—			—			2,918
Net benefit cost recognized for financial reporting	$	37,425		$	32,214		$	5,660		$	17,228

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	1.3
Unrecognized tax benefit — Temporary tax positions	9.4		8.3
Total unrecognized tax benefit	$	11.8	$	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)	Sept. 30, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(7.8	)	$	(5.3	)

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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		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 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	$ (23,120)	$ (18,865)	$ (22,871)	$ (12,377)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	11	(3,574)	(2)	(9,311)
After-tax net realized gains on derivative transactions reclassified into earnings	(119)	(304)	(355)	(1,055)
Accumulated other comprehensive loss related to cash flow hedges at end of period	$ (23,228)	$ (22,743)	$ (23,228)	$ (22,743)

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) (USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 154,000,000
Commercial Paper
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	0	8,000,000
Maximum amount outstanding	0	165,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)		0.33%
Weighted average interest rate at period end (in hundredths)		0.35%
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000,000	250,000,000
Amount outstanding at period end	0	0
Average amount outstanding	0	300,000
Maximum amount outstanding	$ 0	$ 8,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)		0.33%

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Rate Matters (Details) (USD $)	0 Months Ended	1 Months Ended														9 Months Ended	1 Months Ended	3 Months Ended			1 Months Ended
	Aug. 30, 2013 Production Formula Rate ROE Complaint [Member]	Apr. 30, 2013 Colorado Public Utilities Commission [Member] 2013 Gas Rate Case [Member] Counterparty	Dec. 31, 2012 Colorado Public Utilities Commission [Member] 2013 Gas Rate Case [Member]	Apr. 30, 2013 Colorado Public Utilities Commission [Member] Gas Rate Case 2013, Gas Rates 2013 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Gas Rate Case 2013, Gas Rates 2013 [Member]	Apr. 30, 2013 Colorado Public Utilities Commission [Member] Gas Rate Case 2013, Gas Rates 2014 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Gas Rate Case 2013, Gas Rates 2014 [Member]	Apr. 30, 2013 Colorado Public Utilities Commission [Member] Gas Rate Case 2013, Gas Rates 2015 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Gas Rate Case 2013, Gas Rates 2015 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Gas Rate Case 2013, Pipeline System Integrity Adjustment 2014 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Gas Rate Case 2013, Pipeline System Integrity Adjustment 2015 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Steam Rate Case 2013 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Steam Rate Case 2013, Steam Rates 2013 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Steam Rate Case 2013, Steam Rates 2014 [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Steam Rate Case 2013, Steam Rates 2015 [Member]	Sep. 30, 2013 Colorado Public Utilities Commission [Member] Annual Electric Earnings Test [Member]	Mar. 31, 2012 Colorado Public Utilities Commission [Member] Renewable Energy Credit Sharing [Member]	Sep. 30, 2013 Colorado Public Utilities Commission [Member] Renewable Energy Credit Sharing [Member]	Sep. 30, 2012 Colorado Public Utilities Commission [Member] Renewable Energy Credit Sharing [Member]	Dec. 31, 2012 Colorado Public Utilities Commission [Member] Renewable Energy Credit Sharing [Member]	Mar. 31, 2012 Colorado Public Utilities Commission [Member] Renewable Energy Credit Sharing [Member] Shareholders [Member]	May 31, 2011 Colorado Public Utilities Commission [Member] Renewable Energy Credit Sharing [Member] Shareholders [Member]	Mar. 31, 2012 Colorado Public Utilities Commission [Member] Renewable Energy Credit Sharing [Member] Customers [Member]	May 31, 2011 Colorado Public Utilities Commission [Member] Renewable Energy Credit Sharing [Member] Customers [Member]	Jul. 31, 2013 Colorado Public Utilities Commission [Member] Electric Commodity Adjustment / RESA Adjustment [Member]	Apr. 30, 2013 Office of Consumer Counsel [Member] 2013 Gas Rate Case [Member]	Oct. 31, 2013 Subsequent Event [Member] Colorado Public Utilities Commission [Member] Steam Rate Case 2013, Steam Rates 2014 [Member]	Oct. 31, 2013 Subsequent Event [Member] Administrative Law Judge [Member] 2013 Gas Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 48,500,000		$ 9,900,000		$ 12,100,000	$ 26,800,000	$ 24,700,000		$ 1,600,000	$ 900,000	$ 2,300,000
Public Utilities, Requested Return on Equity, Percentage		10.30%	10.50%									10.50%
Public Utilities, Requested Rate Base, Amount			1,300,000,000									21,000,000
Public Utilities, Requested Equity Capital Structure, Percentage			56.00%									56.00%
Number of days subject to refund																											60
Public Utilities, Approved Rate Increase (Decrease), Amount																											1,200,000
Public Utilities, Number of intervenors filing testimony		4
Public Utilities, Incremental Base Revenue increase (decrease) recommended by third party		(1,100,000)																								15,400,000		15,000,000
Public Utilities, Return on equity recommended by third parties		9.00%																								9.00%		9.72%
Public Utilities, Equity capital structure recommended by third parties		52.00%																								51.03%		56.00%
Public Utilities, Adjustment requested by third parties related to return on equity and capital structure adjustments		(20,800,000)																								(20,000,000)		(7,700,000)
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to use of 13 month average from year end rate base		(5,700,000)																								(3,200,000)		(3,300,000)
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to removal of pension asset		(5,900,000)																								0		0
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to incentive compensation		(3,500,000)																								(200,000)		(200,000)
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to challenge of known and measurable		0																								(9,000,000)		0
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to elimination of depreciation annualization		0																								(1,800,000)		0
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to revenue adjustments		(4,100,000)																								(1,400,000)		(1,400,000)
Public Utilities, Tax impact of adjustments to requested rate increase (decrease) requested by third parties		1,500,000																								4,700,000		(200,000)
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs		(4,200,000)																								3,100,000		(1,200,000)
Public Utilities, Rate increase (decrease) recommended by third parties		(15,300,000)																								1,200,000		29,200,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				44,800,000		9,000,000		10,900,000
Public Utilities, Return on equity used in weather normalized earnings test																10.00%
Public Utilities, Refund to customers due to weather normalized earnings test																8,200,000
Public Utilities, Initial percentage of margin associated with stand alone REC transactions																						20.00%		80.00%
Public Utilities, Ultimate percentage of margin associated with stand alone REC transactions																						10.00%		90.00%
Public Utilities, Margin threshold determining percentage of margin sharing																	20,000,000
Public Utilities, Percentage of margin on hybrid REC approved for first 20 million of margins																					20.00%		80.00%
Public Utilities, Percentage of margin on hybrid REC approved for margins in excess of 20 million																					10.00%		90.00%
Public Utilities, Customers share of margins credited against RESA regulatory asset balance																		6,100,000	6,200,000
Public Utilities, Cumulative credit against RESA regulatory asset balance																		99,400,000		82,800,000
Return on equity for third parties, lower bound	10.10%
Return on equity for third parties, upper bound	10.40%
Proposed return on equity recommended by third parties	9.04%
Potential prospective annual revenue increase (decrease)	(2,000,000)
Proposed transfer between ECA and RESA deferred accounts																									26,200,000
Proposed Amortization Period For Recovery Of Deferred Costs																									12
Interest Expense, Other																									2,600,000
Public Utilities, Adjustment for historic test year		(1,600,000)																								(1,600,000)		(1,600,000)
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to pension expense net of corrections		(1,600,000)																								0		0
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to removal of PSIA from base rates		(14,200,000)																								(14,200,000)		0
Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to neutralization of PSIA - base rate transfer		14,200,000																								14,200,000		(14,200,000)
Public Utilities, Revenue deficiency based on a forecast test year				$ 30,600,000

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Commitments and Contingencies, Purchased Power Agreements (Details) (Independent Power Producing Entities)	Sep. 30, 2013 MW	Dec. 31, 2012 MW
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,441	1,433

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Income Taxes

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes

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 Sept. 30, 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 Sept. 30, 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 Sept. 30, 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)	Sept. 30, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	1.3
Unrecognized tax benefit — Temporary tax positions	9.4		8.3
Total unrecognized tax benefit	$	11.8	$	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)	Sept. 30, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(7.8	)	$	(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 Sept. 30, 2013 and Dec. 31, 2012 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2013 or Dec. 31, 2012.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As PSCo had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.

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Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2013

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Loss, Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at July 1	$	(23,120	)
Other comprehensive gain before reclassifications	11
Gains reclassified from net accumulated other comprehensive loss	(119		)
Net current period other comprehensive loss	(108		)
Accumulated other comprehensive loss at Sept. 30	$	(23,228	)

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(22,871	)
Other comprehensive loss before reclassifications	(2		)
Gains reclassified from net accumulated other comprehensive loss	(355		)
Net current period other comprehensive loss	(357		)
Accumulated other comprehensive loss at Sept. 30	$	(23,228	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2013				Nine Months Ended Sept. 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(184	)	(a)	$	(546	)	(a)
Vehicle fuel derivatives	(11		)	(b)	(30		)	(b)
Total, pre-tax	(195		)		(576		)
Tax expense	76				221
Total amounts reclassified, net of tax	$	(119	)		$	(355	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) (First Mortgage Bonds, USD $)	1 Months Ended
	Mar. 31, 2013
Series Due March 15, 2023
Long-Term Borrowings [Abstract]
Face amount	$ 250,000,000
Interest rate, stated percentage (in hundredths)	2.50%
Maturity date	Mar. 15, 2023
Series Due March 15, 2043
Long-Term Borrowings [Abstract]
Face amount	$ 250,000,000
Interest rate, stated percentage (in hundredths)	3.95%
Maturity date	Mar. 15, 2043

XML

Borrowings and Other Financing Instruments

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

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 Sept. 30, 2013		Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		0.3
Maximum amount outstanding	—		8
Weighted average interest rate, computed on a daily basis	N/A		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 Sept. 30, 2013		Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700	$	700
Amount outstanding at period end	—		154
Average amount outstanding	—		8
Maximum amount outstanding	—		165
Weighted average interest rate, computed on a daily basis	N/A		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 Sept. 30, 2013 and Dec. 31, 2012, there were $6.9 million and $4.0 million of letters of credit outstanding, respectively, under the credit facility.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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

At Sept. 30, 2013, PSCo had the following committed credit facility available (in millions of dollars): 

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	6.9	$	693.1

^(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 Sept. 30, 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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Selected Balance Sheet Data

9 Months Ended

Sep. 30, 2013

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	305,360		$	299,379
Less allowance for bad debts	(22,537		)	(21,918		)
	$	282,823		$	277,461

(Thousands of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	55,869	$	54,486
Fuel	86,597		89,246
Natural gas	108,768		80,062
	$	251,234	$	223,794

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	10,045,683		$	9,782,163
Natural gas plant	2,662,749			2,583,394
Common and other property	749,437			761,712
Plant to be retired (a)	115,753			152,730
Construction work in progress	850,106			506,225
Total property, plant and equipment	14,423,728			13,786,224
Less accumulated depreciation	(3,921,853		)	(3,755,233		)
	$	10,501,875		$	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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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 15,446	$ 5,150
Accounts receivable, net	282,823	277,461
Accounts receivable from affiliates	26,235	93,544
Investments in utility money pool arrangement	135,000	0
Accrued unbilled revenues	205,277	285,624
Inventories	251,234	223,794
Regulatory assets	142,973	143,689
Deferred income taxes	63,784	0
Derivative instruments	8,181	4,889
Prepayments and other	18,504	22,970
Total current assets	1,149,457	1,057,121
Property, plant and equipment, net	10,501,875	10,030,991
Other assets
Regulatory assets	904,546	934,728
Derivative instruments	7,333	10,868
Other	50,000	50,461
Total other assets	961,879	996,057
Total assets	12,613,211	12,084,169
Current liabilities
Current portion of long-term debt	281,906	256,297
Short-term debt	0	154,000
Accounts payable	332,775	359,969
Accounts payable to affiliates	34,800	30,001
Regulatory liabilities	47,204	33,723
Taxes accrued	158,996	153,614
Accrued interest	31,838	48,014
Dividends payable to parent	65,000	66,803
Derivative instruments	8,084	8,753
Other	68,528	72,669
Total current liabilities	1,029,131	1,183,843
Deferred credits and other liabilities
Deferred income taxes	2,091,827	1,782,828
Deferred investment tax credits	39,926	42,097
Regulatory liabilities	428,344	417,404
Asset retirement obligations	44,505	43,751
Derivative instruments	24,663	30,605
Customer advances	241,705	229,498
Pension and employee benefit obligations	280,486	324,625
Other	67,614	69,307
Total deferred credits and other liabilities	3,219,070	2,940,115
Commitments and contingencies
Capitalization
Long-term debt	3,592,116	3,374,476
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at Sept. 30, 2013 and Dec. 31, 2012	0	0
Additional paid in capital	3,420,154	3,415,669
Retained earnings	1,375,968	1,192,937
Accumulated other comprehensive loss	(23,228)	(22,871)
Total common stockholder’s equity	4,772,894	4,585,735
Total liabilities and equity	$ 12,613,211	$ 12,084,169

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Benefit Plans and Other Postretirement Benefits (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost	$ 6,302,000	$ 5,679,000	$ 18,905,000	$ 17,039,000
Interest cost	11,540,000	12,776,000	34,620,000	38,329,000
Expected return on plan assets	(15,955,000)	(16,326,000)	(47,865,000)	(48,977,000)
Amortization of transition obligation	0	0	0	0
Amortization of prior service (credit) cost	(266,000)	57,000	(798,000)	171,000
Amortization of net loss	10,855,000	8,552,000	32,563,000	25,652,000
Net periodic benefit cost	12,476,000	10,738,000	37,425,000	32,214,000
Additional cost recognized due to the effects of regulation	0	0	0	0
Net benefit cost recognized for financial reporting	12,476,000	10,738,000	37,425,000	32,214,000
Total contributions to Xcel Energy's pension plans during the period			44,400,000
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost	803,000	706,000	2,409,000	2,119,000
Interest cost	5,934,000	6,131,000	17,802,000	18,395,000
Expected return on plan assets	(7,307,000)	(6,264,000)	(21,921,000)	(18,792,000)
Amortization of transition obligation	196,000	2,751,000	588,000	8,253,000
Amortization of prior service (credit) cost	(1,229,000)	(1,288,000)	(3,687,000)	(3,863,000)
Amortization of net loss	3,490,000	2,734,000	10,469,000	8,198,000
Net periodic benefit cost	1,887,000	4,770,000	5,660,000	14,310,000
Additional cost recognized due to the effects of regulation	0	972,000	0	2,918,000
Net benefit cost recognized for financial reporting	1,887,000	5,742,000	5,660,000	17,228,000
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 192,200,000
Number of Xcel Energy's pension plans to which contributions were made	4		4

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 400,000		$ 600,000
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0		0
Fair Value Measured on a Recurring Basis | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8,181,000		4,889,000
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Purchased Power Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,715,000	[1]	1,715,000	[1]
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6,466,000		3,174,000
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	33,000		43,000
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,811,000		3,131,000
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,622,000		0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7,333,000		10,868,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Purchased Power Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7,321,000	[1]	8,607,000	[1]
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,000		2,261,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,000		39,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			2,222,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	8,084,000		8,753,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Purchased Power Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	5,395,000	[1]	5,429,000	[1]
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,689,000		3,324,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,689,000		3,246,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			78,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	24,663,000		30,605,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Purchased Power Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	24,663,000	[1]	28,701,000	[1]
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			1,904,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			1,904,000
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8,973,000		6,482,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	33,000		43,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,318,000		6,432,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,622,000		7,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,000		3,807,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,000		39,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			3,768,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	4,844,000		6,043,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	4,844,000		5,958,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			85,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			3,450,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			3,450,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8,973,000		6,482,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	33,000		43,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,318,000		6,432,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,622,000		7,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,000		3,807,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,000		39,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			3,768,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	4,844,000		6,043,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	4,844,000		5,958,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			85,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			3,450,000
Fair Value Measured on a Recurring Basis | Fair Value Total [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			3,450,000
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(2,507,000)	[2]	(3,308,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[2]	0	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(2,507,000)	[2]	(3,301,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[2]	(7,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[2]	(1,546,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[2]	0	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			(1,546,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(2,155,000)	[2]	(2,719,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(2,155,000)	[2]	(2,712,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			(7,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			(1,546,000)	[3]
Fair Value Measured on a Recurring Basis | Counterparty Netting [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			$ (1,546,000)	[3]

[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 Sept. 30, 2013. At Sept. 30, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.4 million and no rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[3] 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 Dec. 31, 2012. At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and no rights to reclaim cash collateral. 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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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 14,423,728		$ 13,786,224
Less accumulated depreciation	(3,921,853)		(3,755,233)
Property, plant and equipment, net	10,501,875		10,030,991
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	10,045,683		9,782,163
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,662,749		2,583,394
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	749,437		761,712
Plant to be retired
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	115,753	[1]	152,730	[1]
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 850,106		$ 506,225

[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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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Segment Information

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.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2013
Operating revenues from external customers	$	898,811	$	137,349	$	8,140	$	—		$	1,044,300
Intersegment revenues	67		3		—		(70		)	—
Total revenues	$	898,878	$	137,352	$	8,140	$	(70	)	$	1,044,300
Net income	$	158,498	$	3,555	$	4,213	$	—		$	166,266

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2013
Operating revenues from external customers	$	2,368,041	$	730,569	$	29,576	$	—		$	3,128,186
Intersegment revenues	215		75		—		(290		)	—
Total revenues	$	2,368,256	$	730,644	$	29,576	$	(290	)	$	3,128,186
Net income	$	322,569	$	46,141	$	11,460	$	—		$	380,170

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

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 1,441 megawatts (MW) and 1,433 MW of capacity under long-term purchased power agreements as of Sept. 30, 2013 and Dec. 31, 2012, respectively, with entities that have been determined to be variable interest entities.  PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  These agreements have expiration dates through the year 2028.

Environmental Contingencies

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard (NSPS) Proposal and Emission Guideline for Existing Sources — In September 2013, the U.S. Environmental Protection Agency (EPA) re-proposed a GHG NSPS for newly constructed power plants which seeks to establish carbon dioxide (CO₂) emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.

Federal Clean Water Act - Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. A final rule is anticipated in 2014. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on PSCo is uncertain at this time.

Regional Haze Rules — In 2005, the 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 $343.0 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 10^th 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

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.  In May 2013, the Fifth Circuit affirmed the district court’s dismissal of this lawsuit. Plaintiffs elected not to seek further review of this decision, which brings this litigation to a close.  No accrual was 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 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.

In April 2013, the FERC issued an order on rehearing.   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 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 what claim Seattle has against PSCo prior to June 2000. In the proceeding, Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive. A FERC hearing on the issue is presently in progress. An ALJ initial decision is expected in December 2013.

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding 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 has been 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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Selected Balance Sheet Data (Tables)

9 Months Ended

Sep. 30, 2013

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	305,360		$	299,379
Less allowance for bad debts	(22,537		)	(21,918		)
	$	282,823		$	277,461

Inventories

(Thousands of Dollars)	Sept. 30, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	55,869	$	54,486
Fuel	86,597		89,246
Natural gas	108,768		80,062
	$	251,234	$	223,794

Property, Plant and Equipment, Net

(Thousands of Dollars)	Sept. 30, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	10,045,683		$	9,782,163
Natural gas plant	2,662,749			2,583,394
Common and other property	749,437			761,712
Plant to be retired (a)	115,753			152,730
Construction work in progress	850,106			506,225
Total property, plant and equipment	14,423,728			13,786,224
Less accumulated depreciation	(3,921,853		)	(3,755,233		)
	$	10,501,875		$	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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Benefit Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,302		$	5,679		$	803		$	706
Interest cost	11,540			12,776			5,934			6,131
Expected return on plan assets	(15,955		)	(16,326		)	(7,307		)	(6,264		)
Amortization of transition obligation	—			—			196			2,751
Amortization of prior service (credit) cost	(266		)	57			(1,229		)	(1,288		)
Amortization of net loss	10,855			8,552			3,490			2,734
Net periodic benefit cost	12,476			10,738			1,887			4,770
Additional cost recognized due to the effects of regulation	—			—			—			972
Net benefit cost recognized for financial reporting	$	12,476		$	10,738		$	1,887		$	5,742

	Nine Months Ended Sept. 30
	2013			2012			2013			2012
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	18,905		$	17,039		$	2,409		$	2,119
Interest cost	34,620			38,329			17,802			18,395
Expected return on plan assets	(47,865		)	(48,977		)	(21,921		)	(18,792		)
Amortization of transition obligation	—			—			588			8,253
Amortization of prior service (credit) cost	(798		)	171			(3,687		)	(3,863		)
Amortization of net loss	32,563			25,652			10,469			8,198
Net periodic benefit cost	37,425			32,214			5,660			14,310
Additional cost recognized due to the effects of regulation	—			—			—			2,918
Net benefit cost recognized for financial reporting	$	37,425		$	32,214		$	5,660		$	17,228

In 2013, contributions of $192.2 million were made across four of Xcel Energy’s pension plans, of which $44.4 million was attributable to PSCo.  Xcel Energy does not expect additional pension contributions during 2013.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 28, 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
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

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Other Comprehensive Income

9 Months Ended

Sep. 30, 2013

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at July 1	$	(23,120	)
Other comprehensive gain before reclassifications	11
Gains reclassified from net accumulated other comprehensive loss	(119		)
Net current period other comprehensive loss	(108		)
Accumulated other comprehensive loss at Sept. 30	$	(23,228	)

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(22,871	)
Other comprehensive loss before reclassifications	(2		)
Gains reclassified from net accumulated other comprehensive loss	(355		)
Net current period other comprehensive loss	(357		)
Accumulated other comprehensive loss at Sept. 30	$	(23,228	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2013				Nine Months Ended Sept. 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(184	)	(a)	$	(546	)	(a)
Vehicle fuel derivatives	(11		)	(b)	(30		)	(b)
Total, pre-tax	(195		)		(576		)
Tax expense	76				221
Total amounts reclassified, net of tax	$	(119	)		$	(355	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.