UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM ~~10-Q/A~~

~~(Amendment No. 1)~~

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~~March 31, 2014



¨	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~~May 5, 2014
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.

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~~EXPLANATORY NOTE~~



PART I — FINANCIAL INFORMATION

Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 4 —	Controls and Procedures	26

PART II — OTHER INFORMATION

Item 1 —	Legal Proceedings	26
Item 1A —	Risk Factors	26
Item 4 —	Mine Safety Disclosures	26
Item 5 —	Other Information	27
Item 6 —	Exhibits	27

SIGNATURES		28

Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This ~~Amendment No. 1 to~~Form 10-Q is filed by Public Service Company of ~~Colorado's~~Colorado, a Colorado corporation (PSCo). PSCo is a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); PSCo; and Southwestern Public Service Company, a New Mexico corporation (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended March 31
	2014			2013
Operating revenues
Electric	$	734,264		$	721,348
Natural gas	456,337			383,924
Steam and other	12,942			12,185
Total operating revenues	1,203,543			1,117,457

Operating expenses
Electric fuel and purchased power	334,470			319,881
Cost of natural gas sold and transported	309,805			249,620
Cost of sales — steam and other	4,978			4,805
Operating and maintenance expenses	175,524			173,041
Demand side management program expenses	35,195			33,121
Depreciation and amortization	93,316			89,550
Taxes (other than income taxes)	41,818			35,140
Total operating expenses	995,106			905,158

Operating income	208,437			212,299

Other income, net	797			1,577
Allowance for funds used during construction — equity	11,430			5,923

Interest charges and financing costs
Interest charges — includes other financing costs of $1,720 and $1,648, respectively	43,972			41,388
Allowance for funds used during construction — debt	(4,208		)	(2,151		)
Total interest charges and financing costs	39,764			39,237

Income before income taxes	180,900			180,562
Income taxes	62,497			63,957
Net income	$	118,403		$	116,605

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended March 31
	2014			2013
Net income	$	118,403		$	116,605

Other comprehensive loss

Derivative instruments:
Net fair value (decrease) increase, net of tax of $(2) and $4, respectively	(3		)	7
Reclassification of gains to net income, net of tax of $(73) and $(74), respectively	(120		)	(118		)

Other comprehensive loss	(123		)	(111		)
Comprehensive income	$	118,280		$	116,494

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)



	Three Months Ended March 31
	2014			2013
Operating activities
Net income	$	118,403		$	116,605
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	94,654			90,809
Demand side management program amortization	1,144			1,257
Deferred income taxes	41,863			66,372
Amortization of investment tax credits	(734		)	(740		)
Allowance for equity funds used during construction	(11,430		)	(5,923		)
Net realized and unrealized hedging and derivative transactions	2,818			(164		)
Changes in operating assets and liabilities:
Accounts receivable	410			41,048
Accrued unbilled revenues	63,760			49,579
Inventories	56,296			42,434
Prepayments and other	7,395			(10,662		)
Accounts payable	(29,270		)	(18,383		)
Net regulatory assets and liabilities	10,199			67,907
Other current liabilities	38,157			10,870
Pension and other employee benefit obligations	(35,614		)	(44,273		)
Change in other noncurrent assets	4,616			3,779
Change in other noncurrent liabilities	(891		)	1,720
Net cash provided by operating activities	361,776			412,235

Investing activities
Utility capital/construction expenditures	(299,086		)	(226,948		)
Allowance for equity funds used during construction	11,430			5,923
Investments in utility money pool arrangement	(495,000		)	(276,000		)
Repayments from utility money pool arrangement	317,000			76,000
Net cash used in investing activities	(465,656		)	(421,025		)

Financing activities
Repayments of short-term borrowings, net	—			(154,000		)
Borrowings under utility money pool arrangement	2,000			14,000
Repayments under utility money pool arrangement	(2,000		)	(14,000		)
Proceeds from issuance of long-term debt	296,045			493,164
Repayments of long-term debt	—			(250,000		)
Dividends paid to parent	(195,134		)	(66,803		)
Net cash provided by financing activities	100,911			22,361

Net change in cash and cash equivalents	(2,969		)	13,571
Cash and cash equivalents at beginning of period	21,089			5,150
Cash and cash equivalents at end of period	$	18,120		$	18,721

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(55,003	)	$	(54,770	)
Cash received (paid) for income taxes, net	4,902			(16,308		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	93,872		$	81,470

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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



	March 31, 2014			Dec. 31, 2013
Assets
Current assets
Cash and cash equivalents	$	18,120		$	21,089
Accounts receivable, net	316,348			328,675
Accounts receivable from affiliates	31,053			19,136
Investments in utility money pool arrangement	250,000			72,000
Accrued unbilled revenues	207,157			270,917
Inventories	181,711			238,007
Regulatory assets	167,115			150,163
Deferred income taxes	67,319			87,267
Derivative instruments	2,343			6,576
Prepayments and other	25,234			32,629
Total current assets	1,266,400			1,226,459

Property, plant and equipment, net	10,901,885			10,742,397

Other assets
Regulatory assets	838,996			826,037
Derivative instruments	6,471			6,905
Other	50,163			52,520
Total other assets	895,630			885,462
Total assets	$	13,063,915		$	12,854,318

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	282,389		$	282,143
Accounts payable	386,917			451,243
Accounts payable to affiliates	32,727			45,902
Regulatory liabilities	92,617			79,499
Taxes accrued	205,841			154,194
Accrued interest	31,980			48,492
Dividends payable to parent	64,022			65,134
Derivative instruments	5,857			6,734
Other	91,988			89,571
Total current liabilities	1,194,338			1,222,912

Deferred credits and other liabilities
Deferred income taxes	2,235,374			2,206,179
Deferred investment tax credits	38,496			39,230
Regulatory liabilities	449,883			424,690
Asset retirement obligations	61,129			60,398
Derivative instruments	22,068			23,366
Customer advances	248,292			251,062
Pension and employee benefit obligations	131,513			167,127
Other	68,853			66,855
Total deferred credits and other liabilities	3,255,608			3,238,907

Commitments and contingencies
Capitalization
Long-term debt	3,887,712			3,590,500
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at March 31, 2014 and Dec. 31, 2013	—			—
Additional paid in capital	3,441,290			3,441,290
Retained earnings	1,308,428			1,384,047
Accumulated other comprehensive loss	(23,461		)	(23,338		)
Total common stockholder’s equity	4,726,257			4,801,999
Total liabilities and equity	$	13,063,915		$	12,854,318

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of March 31, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2014 and 2013; and its cash flows for the three months ended March 31, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2014 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, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013. 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, 2013, filed with the SEC on Feb. 24, 2014. 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, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently issued accounting pronouncements that have been adopted in the current period did not materially impact the consolidated financial statements, and no material impact is expected from accounting pronouncements issued and pending implementation.


3.	Selected Balance Sheet Data



(Thousands of Dollars)	March 31, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	338,230		$	351,180
Less allowance for bad debts	(21,882		)	(22,505		)
	$	316,348		$	328,675



(Thousands of Dollars)	March 31, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	52,814	$	53,127
Fuel	78,013		86,062
Natural gas	50,884		98,818
	$	181,711	$	238,007

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(Thousands of Dollars)	March 31, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	10,243,897		$	10,177,056
Natural gas plant	2,819,984			2,757,605
Common and other property	762,750			762,916
Plant to be retired ^(a)	92,050			101,279
Construction work in progress	1,056,489			952,469
Total property, plant and equipment	14,975,170			14,751,325
Less accumulated depreciation	(4,073,285		)	(4,008,928		)
	$	10,901,885		$	10,742,397


^(a)	As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation.


4.	Income Taxes

Except to the extent noted below, the circumstances set forth in Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 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, including the 2009 carryback claim. As of March 31, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. PSCo is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2014, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

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



(Millions of Dollars)	March 31, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.3	$	2.5
Unrecognized tax benefit — Temporary tax positions	6.1		5.9
Total unrecognized tax benefit	$	7.4	$	8.4

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



(Millions of Dollars)	March 31, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(3.6	)	$	(7.0	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 million.

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The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2014 or Dec. 31, 2013.


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, 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 was 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. Interim rates, subject to refund, went into effect in August 2013.

In April 2013, PSCo 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 included amounts to be transferred from the Pipeline System Integrity Adjustment (PSIA) rider mechanism.

In December 2013, the CPUC approved a natural gas base rate increase of approximately $15.8 million based on an ROE of 9.72 percent, a historic test year (HTY) with an end of year rate base and an equity ratio of 56 percent.

The following table summarizes the CPUC decision:



(Millions of Dollars)	CPUC Decision
PSCo deficiency based on a FTY	$	44.8
HTY adjustment	(5.4		)
ROE and capital structure adjustments	(8.3		)
Revenue adjustments	(1.4		)
Other	(0.1		)
Recommendation	29.6
PSIA — base rate transfer to rider mechanism	(13.8		)
Incremental base revenue	$	15.8

Rates and conforming changes made to the PSIA were effective Jan. 1, 2014. In April 2014, the CPUC approved PSCo’s request to refund $6.6 million to customers, excluding amounts related to the PSIA rider mechanism. The refund represents the difference between the interim rates collected and the final approved rates and will be returned between April 2014 and March 2015.

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 was 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 Office of Consumer Counsel (OCC) and Colorado Energy Consumers filed a comprehensive settlement which tied the outcome of the steam rate case to key issues to be decided in the natural gas rate case, including ROE and capital structure. The settlement allowed the filed rates to be effective on Jan. 1, 2014, subject to refund. Final rates allowing a rate increase of $2.3 million annually were implemented on Feb. 1, 2014.

Annual Electric Earnings Test — An earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year that exceed PSCo’s authorized ROE threshold of 10 percent. PSCo filed a tariff for the 2013 earnings test with the CPUC on April 30, 2014, proposing a refund obligation of $45.7 million to electric customers to be returned between August 2014 and July 2015. As of March 31, 2014, PSCo has also recognized management’s best estimate of an accrual for 2014.

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Electric Commodity Adjustment (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 Administrative Law Judge (ALJ), will primarily consider if replacement power costs during outages of certain jointly owned facilities were properly allocated between wholesale and retail customers. A decision is anticipated later in 2014.

2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report, requesting $43.5 million for recovery of expenditures. The OCC and CPUC Staff requested that 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. In July 2013, the CPUC approved the request and assigned the matter to an ALJ.

In February 2014, PSCo, the CPUC Staff and the OCC agreed to a settlement amount of $43.4 million for recovery of 2012 expenditures, subject to final approval. This includes a one-time disallowance of approximately $0.1 million of operating and maintenance (O&M) expenditures in 2012 and an agreement not to disallow capital expenditures related to a pipeline replacement project. In March 2014, the ALJ waived the need for a hearing on the settlement. An ALJ recommended decision is anticipated later in 2014.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent to customers for 2014. In 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 renewable energy standard adjustment (RESA) regulatory asset balance. PSCo’s credit to the RESA regulatory asset balance was not material for the three months ended March 31, 2014. For the three months ended March 31, 2013, PSCo credited the RESA regulatory asset balance $4.0 million. The cumulative credit to the RESA regulatory asset balance was $104.6 million and $104.5 million at March 31, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds.

This sharing mechanism will be effective through 2014. The CPUC is then expected to review the framework and evidence regarding actual deliveries before determining whether to continue the sharing mechanism.

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. 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. In 2014, the ALJ and the CPUC determined that the $26.2 million was prudently incurred and recommended full recovery through the ECA over a 12 month period with interest accrued at the ECA interest rate. The difference between the RESA interest rate and the ECA interest rate was a decrease of approximately 7.4 percent, or $4.3 million, and was reflected in 2013 earnings.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

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

In June 2012, several wholesale customers filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. If implemented, the ROE reduction would reduce PSCo transmission and ancillary rate revenues by approximately $1.8 million annually. In October 2012, the FERC issued an order accepting the complaint, consolidating the complaint with the April 2012 formula rate change filing, establishing a refund effective date of July 1, 2012, and setting the complaint for settlement judge and hearing procedures.

In December 2013, the FERC approved a partial settlement resolving all issues related to the April 2012 transmission rate filing and June 2012 complaint other than ROE. The settlement is not expected to materially increase 2014 transmission revenues. The ROE issue is now subject to an evidentiary hearing process.

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In March 2014, the FERC Staff filed testimony supporting an ROE of 8.91 percent for July 2012 to November 2012, and an ROE of 8.70 percent thereafter. The case is scheduled for a hearing before an ALJ in May 2014, with the ALJ recommended decision expected by September 2014.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5, 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, 2013, 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 (PPAs)

Under certain PPAs, 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 PPAs create a variable interest in the associated independent power producing entity.

PSCo had approximately 1,802 megawatts (MW) and 1,441 MW of capacity under long-term PPAs as of March 31, 2014 and Dec. 31, 2013, 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 2032.

Environmental Contingencies

Environmental Requirements

Water and waste

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the U.S. Environmental Protection Agency (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. The final rule is now expected in September 2015. 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.

Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule is anticipated in May 2014. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements.

Air

Regional Haze Rules — In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, 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. In its first regional haze state implementation plan (SIP), Colorado identified the PSCo facilities that will have to reduce sulfur dioxide, nitrous oxide and particulate matter emissions under BART and set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a SIP that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Emission controls at the Hayden and Pawnee plants are projected to cost $359.7 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates.

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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 Colorado SIP. WildEarth Guardians has stated it will challenge the BART determination made for Comanche Units 1 and 2. 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 intervened in the case. The 10^th Circuit is anticipated to hear argument in January 2015, following completion of the briefs in October 2014.

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 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.

Employment, Tort and Commercial Litigation

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding 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. The City of 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 the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of 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.

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A hearing in this case was held before a FERC ALJ and concluded in October 2013. On March 28, 2014, the FERC ALJ issued an initial decision which rejected all of the City of Seattle’s claims against PSCo and other respondents. With respect to the period Jan. 1, 2000 through Dec. 24, 2000, the FERC ALJ rejected the City of Seattle’s assertion that any of the sales made to the City of Seattle resulted in an excessive burden to the City of Seattle, the applicable legal standard for the City of Seattle’s challenges during this period. With respect to the period Dec. 25, 2000 through June 20, 2001, the FERC ALJ concluded that the City of Seattle had failed to establish a causal link between any contracts and any claimed unlawful market activity, the standard required by the FERC in its remand order. The City of Seattle may contest the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC.

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 potentially responsible parties. No accrual has been recorded for this matter.


7.	Borrowings and Other Financing Instruments

Short-Term Borrowings

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



(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	—			0.1
Maximum amount outstanding	2			12
Weighted average interest rate, computed on a daily basis	0.21		%	0.36		%
Weighted average interest rate at period end	N/A			N/A

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



(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	700		$	700
Amount outstanding at period end	—			—
Average amount outstanding	20			38
Maximum amount outstanding	114			332
Weighted average interest rate, computed on a daily basis	0.21		%	0.34		%
Weighted average interest rate at period end	N/A			N/A

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Letters of Credit— PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2014 and Dec. 31, 2013, there were $6.5 million and $6.4 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.

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

At March 31, 2014, PSCo had the following committed credit facility available (in millions of dollars):



Credit Facility ^(a)		Drawn ^(b)		Available
$	700.0	$	6.5	$	693.5


^(a)	Credit facility expires in July 2017.


^(b)	Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at March 31, 2014 and Dec. 31, 2013.

Long-Term Borrowings

In March 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044.


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 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.

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

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

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Derivative Instruments Fair Value Measurements

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

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

At March 31, 2014, accumulated other comprehensive losses related to interest rate derivatives included $0.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges.

Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

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

At March 31, 2014, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2014 and 2013.

At March 31, 2014, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

The following table details the gross notional amounts of commodity forwards and options at March 31, 2014 and Dec. 31, 2013:


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


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

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The following tables detail the impact of derivative activity during the three months ended March 31, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:



	Three Months Ended March 31, 2014
	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	$	—		$	—	$	(180	)	^(a)	$	—			$	—
Vehicle fuel and other commodity	(5		)	—		(13		)	^(b)	—				—
Total	$	(5	)	$	—	$	(193	)		$	—			$	—
Other derivative instruments
Natural gas commodity	$	—		$	9,826	$	—			$	(8,579	)	^(c)	$	(4,316	)	^(c)
Total	$	—		$	9,826	$	—			$	(8,579	)		$	(4,316	)



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


^(a)	Recorded to interest charges.


^(b)	Recorded to O&M expenses.

^(c)

Amounts for the three months ended March 31, 2014 and 2013 included immaterial 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. The remaining derivative settlement gains and losses for the three months ended March 31, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the three months ended March 31, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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.

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

PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At March 31, 2014, five of PSCo’s 10 most significant counterparties, comprising $26.6 million or 27 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. The remaining five significant counterparties, comprising $43.6 million or 45 percent of this credit exposure, 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.

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 $1.1 million and $1.4 million gross liability position on the consolidated balance sheets at March 31, 2014 and Dec. 31, 2013, 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 $1.1 million and $1.4 million at March 31, 2014 and Dec. 31, 2013, respectively. At March 31, 2014 and Dec. 31, 2013, there was no collateral posted on these specific contracts.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2014 and Dec. 31, 2013.

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Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at March 31, 2014:



	March 31, 2014
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	26	$	—	$	26	$	—		$	26
Other derivative instruments:
Commodity trading	—		1,152		—		1,152		(550		)	602
Total current derivative assets	$	—	$	1,178	$	—	$	1,178	$	(550	)	628
PPAs ^(a)												1,715
Current derivative instruments												$	2,343
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	8	$	—	$	8	$	—		$	8
Total noncurrent derivative assets	$	—	$	8	$	—	$	8	$	—		8
PPAs ^(a)												6,463
Noncurrent derivative instruments												$	6,471
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	1,071	$	—	$	1,071	$	(490	)	$	581
Total current derivative liabilities	$	—	$	1,071	$	—	$	1,071	$	(490	)	581
PPAs ^(a)												5,276
Current derivative instruments												$	5,857
Noncurrent derivative liabilities
PPAs ^(a)												22,068
Noncurrent derivative instruments												$	22,068

^(a)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs 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 March 31, 2014. At March 31, 2014, derivative assets and liabilities include obligations to return cash collateral of $0.1 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, 2013:



	Dec. 31, 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	$	—	$	40	$	—	$	40	$	—		$	40
Other derivative instruments:
Commodity trading	—		2,756		—		2,756		(1,276		)	1,480
Natural gas commodity	—		3,341		—		3,341		—			3,341
Total current derivative assets	$	—	$	6,137	$	—	$	6,137	$	(1,276	)	4,861
PPAs ^(a)												1,715
Current derivative instruments												$	6,576
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	13	$	—	$	13	$	—		$	13
Total noncurrent derivative assets	$	—	$	13	$	—	$	13	$	—		13
PPAs ^(a)												6,892
Noncurrent derivative instruments												$	6,905
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	$	1,399
Total current derivative liabilities	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	1,399
PPAs ^(a)												5,335
Current derivative instruments												$	6,734
Noncurrent derivative liabilities
PPAs ^(a)												$	23,366
Noncurrent derivative instruments												$	23,366

^(a)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs 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, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 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 months ended March 31, 2014 and 2013.

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 months ended March 31, 2014 and 2013.

Fair Value of Long-Term Debt

As of March 31, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:



	March 31, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,170,101	$	4,412,893	$	3,872,643	$	4,059,661

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The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of March 31, 2014 and Dec. 31, 2013, 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 March 31
(Thousands of Dollars)	2014			2013
Interest income	$	489		$	914
Other nonoperating income	685			882
Insurance policy expense	(367		)	(219		)
Other nonoperating expense	(10		)	—
Other income, net	$	797		$	1,577


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.

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To report income from 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 March 31, 2014
Operating revenues ^{(a) (b)}	$	734,264	$	456,337	$	12,942	$	—		$	1,203,543
Intersegment revenues	97		59		—		(156		)	—
Total revenues	$	734,361	$	456,396	$	12,942	$	(156	)	$	1,203,543
Net income	$	73,968	$	38,149	$	6,286	$	—		$	118,403



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

^(a)Operating revenues include $2 million and $2 million of intercompany electric revenue for the three months ended March 31, 2014 and 2013, respectively.

^(b)Operating revenues include $1 million and $1 million of other intercompany revenue for the three months ended March 31, 2014 and 2013, respectively.


11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)



	Three Months Ended March 31
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	5,985		$	6,302		$	479		$	803
Interest cost	13,319			11,540			5,926			5,934
Expected return on plan assets	(17,677		)	(15,955		)	(7,554		)	(7,307		)
Amortization of transition obligation	—			—			—			196
Amortization of prior service credit	(773		)	(266		)	(1,562		)	(1,229		)
Amortization of net loss	8,473			10,854			1,609			3,490
Net benefit cost (credit) recognized for financial reporting	$	9,327		$	12,475		$	(1,102	)	$	1,887

In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $35.1 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2014.


12.	Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2014 and 2013 were as follows:



	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended March 31, 2014			Three Months Ended March 31, 2013
Accumulated other comprehensive loss at Jan. 1	$	(23,338	)	$	(22,871	)
Other comprehensive gain (loss) before reclassifications	(3		)	7
Gains reclassified from net accumulated other comprehensive loss	(120		)	(118		)
Net current period other comprehensive loss	(123		)	(111		)
Accumulated other comprehensive loss at March 31	$	(23,461	)	$	(22,982	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2014 and 2013 were as follows:



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2014				Three Months Ended March 31, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(180	)	^(a)	$	(180	)	^(a)
Vehicle fuel derivatives	(13		)	^(b)	(12		)	^(b)
Total, pre-tax	(193		)		(192		)
Tax expense	73				74
Total amounts reclassified, net of tax	$	(120	)		$	(118	)


^(a)	Included in interest charges.


^(b)	Included in O&M expenses.

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of slow down in the U.S. economy or delay in growth recovery; actions of credit rating agencies; trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; 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, 2013, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended ~~Sept.~~March 31, 2014.

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Results of Operations

PSCo’s net income was approximately $118.4 million for the three months ended March 31, 2014, compared with approximately $116.6 million for the same period in 2013. The increase is mainly due to higher electric and natural gas rates and sales growth. These factors were partially offset by increased property taxes, depreciation, and accruals associated with electric earnings test refund obligations.

Electric Revenues and Margin

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



	Three Months Ended March 31
(Millions of Dollars)	2014			2013
Electric revenues	$	734		$	721
Electric fuel and purchased power	(334		)	(320		)
Electric margin	$	400		$	401

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

Electric Revenues



(Millions of Dollars)	2014 vs. 2013
Fuel and purchased power cost recovery	$	16
Retail rate increases	6
Retail sales growth, excluding weather impact	5
Demand side management (DSM) program revenues	3
PSCo earnings test refund obligations	(11		)
Trading, including renewable energy credit sales	(2		)
DSM program incentives	(2		)
Other, net	(2		)
Total increase in electric revenues	$	13

Electric Margin



(Millions of Dollars)	2014 vs. 2013
Retail rate increases	$	6
Retail sales growth, excluding weather impact	5
DSM program revenues	3
PSCo earnings test refund obligations	(11		)
DSM program incentives	(2		)
Other, net	(2		)
Total decrease in electric margin	$	(1	)

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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:



	Three Months Ended March 31
(Millions of Dollars)	2014			2013
Natural gas revenues	$	456		$	384
Cost of natural gas sold and transported	(310		)	(250		)
Natural gas margin	$	146		$	134

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

Natural Gas Revenues



(Millions of Dollars)	2014 vs. 2013
Purchased natural gas adjustment clause recovery	$	61
Retail rate increase, net of refund	9
PSIA rider	4
Retail sales growth	2
Estimated impact of weather	(3		)
Other, net	(1		)
Total increase in natural gas revenues	$	72

Natural Gas Margin



(Millions of Dollars)	2014 vs. 2013
Retail rate increase, net of refund	$	9
PSIA rider, partially offset in O&M expenses	4
Retail sales growth	2
Estimated impact of weather	(3		)
Total increase in natural gas margin	$	12

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased by $2.5 million, or 1.4 percent, for the first quarter of 2014 compared with the same period in 2013. The following table summarizes the changes in O&M expenses:



(Millions of Dollars)	2014 vs. 2013
Electric and gas distribution expenses	$	3
Pipeline system integrity costs	2
Employee benefits	(3		)
Other, net	1
Total increase in O&M expenses	$	3

Electric and gas distribution expenses were primarily driven by increased maintenance activities due to vegetation management; and

Lower employee benefit costs are mainly due to decreased pension expense.

DSM Program Expenses— DSM program expenses increased $2.1 million, or 6.3 percent, for the first quarter of 2014 compared with the same period in 2013. 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 $3.8 million, or 4.2 percent, for the first quarter of 2014 compared with the same period for 2013. The increase is primarily attributable to normal system expansion.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased by $6.7 million, or 19.0 percent, for the first quarter of 2014 compared with the same period in 2013. The increase is primarily due to higher property taxes.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC)— AFUDC increased by $7.6 million for the first quarter of 2014 compared with the same period in 2013. The increase is primarily due to construction related to the CACJA.

Interest Charges —Interest charges increased by $2.6 million, or 6.2 percent, for the first quarter of 2014 compared with the same period in 2013. The increase is primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense decreased $1.5 million for the first quarter of 2014 compared with the same period in 2013. The decrease in income tax expense was primarily due to increased permanent plant-related adjustments in 2014. The ETR was 34.5 percent for the first quarter of 2014 compared with 35.4 percent for the same period in 2013. The lower ETR was primarily due to the same adjustments mentioned above.

Public Utility Regulation

Brush, Colo. to Castle Pines, Colo. 345 Kilovolt (KV) Transmission Line — In March 2014, PSCo filed with the CPUC for a certificate of public convenience and necessity (CPCN) to construct a new 345 KV transmission line originating from Pawnee Station, near Brush, Colo. and terminating at the Daniels Park substation, near Castle Pines, Colo. The estimated cost of the project is $178 million. A CPUC decision is expected in early 2015.

Renewable Energy Standard (RES) Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales be supplied by renewable energy by 2020 and includes a distributed generation standard. In July 2013, PSCo filed its 2014 RES compliance plan that included the continuation of both the Solar*Rewards and Solar*Rewards Community programs. PSCo also proposed to show in aggregate the system costs that are not avoided by distributed solar generation, which PSCo has defined as a “net metering incentive.” In December 2013, parties including the OCC filed answer testimony supporting PSCo’s net metering proposal. However, rooftop solar advocates opposed it and also argued for higher solar installation levels and a slower reduction in incentives over time. The CPUC has bifurcated these issues and determined that matters related to the net metering incentive should be heard in a separate proceeding. Hearings for the 2014 RES compliance plan are scheduled for May 2014 with a decision anticipated in the third quarter of 2014. The CPUC is expected to communicate the process to evaluate the net metering incentive in the second quarter of 2014.

Boulder, Colo. Municipalization Exploration— PSCo’s franchise agreement with the City of Boulder (Boulder) expired on Dec. 31, 2010. In November 2011, a ballot measure was passed by the citizens of Boulder, which authorized the formation and operation of a municipal light and power utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage.

In August 2013, the Boulder City Council voted to authorize the acquisition of PSCo’s transmission and distribution system in and near Boulder. On Jan. 6, 2014, Boulder sent PSCo a Notice of Intent to Acquire (NOIA) for PSCo’s transmission, distribution and property assets within an area that includes Boulder and certain areas outside city limits. The NOIA is a legal prerequisite to the filing of an eminent domain proceeding in Colorado courts. However, sending the NOIA does not require Boulder to move forward with a condemnation case. PSCo has informed Boulder that it believes the NOIA was deficient.

On April 16, 2014, the Boulder City Council passed the first reading of an ordinance to amend its code to create a utility. A public hearing and second vote will take place in May 2014. The ordinance is part of the formal process to create an electric utility and would give Boulder the ability to issue bonds should it decide to move forward with acquiring the Boulder business. The ordinance would give Boulder the means to raise money in a timely manner if it decides to move forward with the muncipalization, and can be repealed if Boulder does not.

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Boulder’s municipalization plan 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 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. The CPUC declared that it 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. In January 2014, Boulder appealed this ruling to Boulder District Court.

If Boulder commences an eminent domain proceeding, PSCo will seek to obtain full compensation for the business and its associated property taken by Boulder, as well as for all damages resulting to PSCo and its system. 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 (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013. 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) — In 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities to develop tariffs that provide for joint 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. PSCo is not in a regional transmission organization and therefore is responsible for making its own Order 1000 compliance filing.

Colorado does not have legislation protecting ROFR rights for incumbent utilities. PSCo submitted its FERC compliance filing 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 in September 2013 to address directives in the March 2013 order. The FERC is expected to rule in 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. The WestConnect members proposed that the regional and inter-regional compliance tariffs be effective prospectively after the final FERC orders, and not earlier than Jan. 1, 2015.

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NERC Critical Infrastructure Protection (CIP) Requirements — The FERC has approved version 5 of NERC’s CIP standards. Requirements must be applied to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. Xcel Energy is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines. Compliance is anticipated to require activities across the organization, including Business Systems, Transmission, Energy Supply and Security Services.

On March 7, 2014, FERC issued an order directing NERC to develop a new critical infrastructure protection standard related to physical security. The order directs NERC to file this standard for approval with FERC within 90 days. NERC has prepared a draft of the proposed standard for industry review and comment. The NERC Board of Trustees will consider industry input and votes on the standards and submit a final standard to FERC no later than June 5, 2014. Xcel Energy is participating in the standard development process and will submit its comments on the proposal to NERC. Xcel Energy is also in the process of evaluating the potential impact on the company as the standard is being ~~filed solely~~developed.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ~~include Exhibit 3.02 which was inadvertently omitted.~~ ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of March 31, 2014, 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 ~~other changes have been made~~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

Additional Information

See Note 6 to the ~~Form 10-Q. This Amendment No. 1~~consolidated financial statements for further discussion of legal claims and environmental proceedings. See Note 5 to the ~~Form 10-Q speaks as~~consolidated financial statements for discussion of ~~the original filing date of the Form 10-Q, does not reflect events that may have occurred subsequent to the original filing date,~~proceedings involving utility rates and ~~does not modify or update in any way disclosures made in the original Form 10-Q~~ other ~~than the inclusion of Exhibit 3.02.~~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, 2013, which is incorporated herein by reference.

Item 4 — MINE SAFETY DISCLOSURES

None.

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Item 5 — OTHER INFORMATION

None.

Item 6 —EXHIBITS



*	Indicates incorporation by reference
#	~~This exhibit is filed or furnished herewith~~
##	~~This exhibit has been previously filed or furnished~~



##3.013.01	Amended and Restated Articles of Incorporation dated July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
~~#3.02~~ 3.02*	By-Laws of PSCo as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03280)).
4.01*	Supplemental Indenture dated as of March 1, 2014 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 4.30 percent First Mortgage Bonds, Series No. 27 due 2044 (Exhibit 4.01 to PSCo’s Form 8-K dated March 10, 2014 (file no. 001-03280)).
#31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
#31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
~~##32.01~~ 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~~ 99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
~~##101~~101	The following materials from PSCo’s Quarterly Report on Form 10-Q for the quarter ended ~~Sept. 30, 2013~~March 31, 2014 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to ~~Condensed~~ Consolidated Financial Statements, and (vi) document and entity information.

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SIGNATURES

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



		Public Service Company of Colorado

~~Nov. 8, 2013~~May 5, 2014	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

(Amounts in Thousands) ^(a)(b)

March 31, 2014

Dec. 31, 2013

Megawatt hours of electricity

Million British thermal units of natural gas

Gallons of vehicle fuel