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 Sept. 30, 2014

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 Nov. 3, 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.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 4 —	Controls and Procedures	29
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	29
Item 1A —	Risk Factors	29
Item 4 —	Mine Safety Disclosures	29
Item 5 —	Other Information	29
Item 6 —	Exhibits	30
SIGNATURES		31
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).

2

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
	2014			2013			2014			2013
Operating revenues
Electric	$	881,102		$	898,811		$	2,376,935		$	2,368,041
Natural gas	159,808			137,349			839,332			730,569
Steam and other	8,201			8,140			30,091			29,576
Total operating revenues	1,049,111			1,044,300			3,246,358			3,128,186
Operating expenses
Electric fuel and purchased power	368,860			355,727			1,052,400			998,395
Cost of natural gas sold and transported	60,073			43,881			487,159			403,198
Cost of sales — steam and other	3,538			3,398			11,951			12,211
Operating and maintenance expenses	185,510			192,073			549,935			553,266
Demand side management program expenses	36,120			38,016			105,993			104,075
Depreciation and amortization	95,075			88,577			283,506			267,206
Taxes (other than income taxes)	38,862			32,887			122,467			104,120
Total operating expenses	788,038			754,559			2,613,411			2,442,471
Operating income	261,073			289,741			632,947			685,715
Other income, net	1,720			946			3,429			3,845
Allowance for funds used during construction — equity	12,315			8,815			36,697			21,529
Interest charges and financing costs
Interest charges — includes other financing costs of $1,546, $1,747,     $4,798, and $5,118, respectively	42,540			43,187			128,941			127,806
Allowance for funds used during construction — debt	(4,564		)	(3,187		)	(13,584		)	(8,438		)
Total interest charges and financing costs	37,976			40,000			115,357			119,368
Income before income taxes	237,132			259,502			557,716			591,721
Income taxes	82,973			93,236			195,362			211,551
Net income	$	154,159		$	166,266		$	362,354		$	380,170

See Notes to Consolidated Financial Statements

3

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
	2014			2013			2014			2013
Net income	$	154,159		$	166,266		$	362,354		$	380,170
Other comprehensive loss
Derivative instruments:
Net fair value (decrease) increase, net of tax of $(10), $5, $(9), and $(2), respectively	(17		)	11			(15		)	(2		)
Reclassification of gains to net income, net of tax of $(72), $(76), $(217), and $(221), respectively	(119		)	(119		)	(356		)	(355		)
Other comprehensive loss	(136		)	(108		)	(371		)	(357		)
Comprehensive income	$	154,023		$	166,158		$	361,983		$	379,813

See Notes to Consolidated Financial Statements

4

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Nine Months Ended Sept. 30
	2014			2013
Operating activities
Net income	$	362,354		$	380,170
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	287,141			271,150
Demand side management program amortization	3,309			3,658
Deferred income taxes	120,585			230,665
Amortization of investment tax credits	(2,202		)	(2,219		)
Allowance for equity funds used during construction	(36,697		)	(21,529		)
Net realized and unrealized hedging and derivative transactions	(6,946		)	(9,052		)
Changes in operating assets and liabilities:
Accounts receivable	55,070			61,660
Accrued unbilled revenues	58,758			80,347
Inventories	(26,409		)	(28,021		)
Prepayments and other	1,001			5,818
Accounts payable	(86,984		)	(28,581		)
Net regulatory assets and liabilities	110,692			74,709
Other current liabilities	(43,323		)	(16,662		)
Pension and other employee benefit obligations	(37,769		)	(44,101		)
Change in other noncurrent assets	5,353			6,917
Change in other noncurrent liabilities	(15,355		)	7,744
Net cash provided by operating activities	748,578			972,673
Investing activities
Utility capital/construction expenditures	(832,270		)	(742,822		)
Allowance for equity funds used during construction	36,697			21,529
Investments in utility money pool arrangement	(587,000		)	(1,086,000		)
Repayments from utility money pool arrangement	659,000			951,000
Net cash used in investing activities	(723,573		)	(856,293		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	253,000			(154,000		)
Borrowings under utility money pool arrangement	303,000			14,000
Repayments under utility money pool arrangement	(292,000		)	(14,000		)
Proceeds from issuance of long-term debt	295,601			492,372
Repayments of long-term debt	(275,000		)	(250,000		)
Capital contributions from parent	35,486			4,485
Dividends paid to parent	(355,547		)	(198,941		)
Net cash used in financing activities	(35,460		)	(106,084		)
Net change in cash and cash equivalents	(10,455		)	10,296
Cash and cash equivalents at beginning of period	21,089			5,150
Cash and cash equivalents at end of period	$	10,634		$	15,446
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(136,045	)	$	(131,378	)
Cash (paid) received for income taxes, net	(67,717		)	41,531
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	125,498		$	100,475

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, 2014			Dec. 31, 2013
Assets
Current assets
Cash and cash equivalents	$	10,634		$	21,089
Accounts receivable, net	272,651			328,675
Accounts receivable from affiliates	20,091			19,136
Investments in utility money pool arrangement	—			72,000
Accrued unbilled revenues	212,160			270,917
Inventories	264,416			238,007
Regulatory assets	108,033			150,163
Deferred income taxes	78,243			87,267
Derivative instruments	7,166			6,576
Prepayments and other	31,628			32,629
Total current assets	1,005,022			1,226,459
Property, plant and equipment, net	11,313,360			10,742,397
Other assets
Regulatory assets	839,823			826,037
Derivative instruments	5,605			6,905
Other	48,955			52,520
Total other assets	894,383			885,462
Total assets	$	13,212,765		$	12,854,318
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	7,854		$	282,143
Short-term debt	253,000			—
Borrowings under utility money pool arrangement	11,000			—
Accounts payable	360,768			451,243
Accounts payable to affiliates	32,789			45,902
Regulatory liabilities	120,842			79,499
Taxes accrued	133,609			154,194
Accrued interest	24,243			48,492
Dividends payable to parent	78,241			65,134
Derivative instruments	5,190			6,734
Other	74,529			89,571
Total current liabilities	1,102,065			1,222,912
Deferred credits and other liabilities
Deferred income taxes	2,338,296			2,206,179
Deferred investment tax credits	37,011			39,230
Regulatory liabilities	470,746			424,690
Asset retirement obligations	98,961			60,398
Derivative instruments	19,546			23,366
Customer advances	236,014			251,062
Pension and employee benefit obligations	129,358			167,127
Other	65,903			66,855
Total deferred credits and other liabilities	3,395,835			3,238,907
Commitments and contingencies
Capitalization
Long-term debt	3,884,051			3,590,500
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at Sept. 30, 2014 and Dec. 31, 2013, respectively	—			—
Additional paid in capital	3,476,776			3,441,290
Retained earnings	1,377,747			1,384,047
Accumulated other comprehensive loss	(23,709		)	(23,338		)
Total common stockholder’s equity	4,830,814			4,801,999
Total liabilities and equity	$	13,212,765		$	12,854,318

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, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2014 and 2013; and its cash flows for the nine months ended Sept. 30, 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 Sept. 30, 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

Revenue Recognition— In May 2014, the Financial Accounting Standards Board issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. PSCo is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	295,333		$	351,180
Less allowance for bad debts	(22,682		)	(22,505		)
	$	272,651		$	328,675

(Thousands of Dollars)	Sept. 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	53,979	$	53,127
Fuel	83,507		86,062
Natural gas	126,930		98,818
	$	264,416	$	238,007

7

(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	10,737,756		$	10,177,056
Natural gas plant	2,930,430			2,757,605
Common and other property	764,710			762,916
Plant to be retired (a)	77,922			101,279
Construction work in progress	995,930			952,469
Total property, plant and equipment	15,506,748			14,751,325
Less accumulated depreciation	(4,193,388		)	(4,008,928		)
	$	11,313,360		$	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 a 2009 carryback claim. As of Sept. 30, 2014, the IRS had proposed an adjustment to several 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 Sept. 30, 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)	Sept. 30, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.3	$	2.5
Unrecognized tax benefit — Temporary tax positions	10.2		5.9
Total unrecognized tax benefit	$	11.5	$	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)	Sept. 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(5.5	)	$	(7.0	)

8

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.

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, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 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 2014 Electric Rate Case —In 2014, PSCo filed an electric rate case with the CPUC requesting an increase in annual revenue of approximately $136.0 million, or 4.83 percent. The requested 2015 rate increase reflects approximately $100.9 million for recovery of costs associated with the CACJA project. The case also requests the initiation of a CACJA rider for 2016 and 2017, which is anticipated to increase revenue recovery by approximately $34.2 million in 2016 and then decline to approximately $29.9 million in 2017. PSCo’s objective is to establish a multi-year regulatory plan that provides certainty for PSCo and its customers.

The rate filing is based on a 2015 test year, a requested return on equity (ROE) of 10.35 percent, an electric rate base of $6.39 billion and an equity ratio of 56 percent. As part of the filing, PSCo will transfer approximately $19.9 million from the transmission rider to base rates, which will not impact customer bills. The CACJA rider is projected to recover incremental investment and expenses, based on a comprehensive plan to retire certain coal plants, add pollution control equipment to other existing coal units and add natural gas generation. The CACJA project investment is expected to be completed by 2017.

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

• Answer Testimony — Nov. 7, 2014;

• Rebuttal Testimony — Dec. 17, 2014;

• Evidentiary Hearing — Jan. 26 - Feb. 4, 2015;

• Interim rates are scheduled to be effective on Feb. 13, 2015, subject to refund; and

• A decision as well as implementation of final rates are anticipated in the second quarter of 2015.

Manufacturer’s Sales Tax Refund —PSCo defers 2012-2014 annual property taxes in excess of $76.7 million as part of its multi-year rate plan with the CPUC. To the extent that PSCo was successful in the manufacturer’s sales tax refund lawsuit against the Colorado Department of Revenue, PSCo was to credit such refunds first against certain legal fees, and then against the unamortized deferred property tax balance at the end of 2014.

On June 30, 2014, the Colorado Supreme Court ruled against PSCo’s claim that it was due refunds for the payment of sales taxes on purchases of certain equipment from December 1998 to December 2001. As a result of the adverse ruling, PSCo is required to reduce its 2014 property tax deferral by $10 million, as this amount will not be recovered in electric rates.  This impact is reflected in PSCo’s pending electric rate case before the CPUC.

Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012-2014. In April 2014, PSCo filed its 2013 earnings test with the CPUC proposing a refund obligation of $45.7 million to electric customers to be returned between August 2014 and July 2015. This tariff was approved by the CPUC in July 2014 and became effective Aug. 1, 2014. As of Sept. 30, 2014, PSCo has also recognized management’s best estimate of an accrual for the 2014 earnings test of $52.4 million.

9

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 Sept. 30, 2014. For the three months ended Sept. 30, 2013, PSCo credited the RESA regulatory asset balance $6.1 million. The cumulative credit to the RESA regulatory asset balance was $104.7 million and $104.5 million at Sept. 30, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds.

In May 2014, PSCo filed with the CPUC to continue this sharing mechanism for 2015 and beyond, but remove the step increase in the sharing allocation of hybrid REC trades on margins in excess of $20 million. In July 2014, the CPUC sent the proceeding to an administrative law judge (ALJ). On Sept. 5, 2014, PSCo, the CPUC Staff, and intervenors filed a settlement agreement to extend the current sharing mechanism without modification through 2017. On Sept. 18, 2014 the ALJ issued a final decision approving the settlement agreement.

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

Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from a historic test year formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million annually. Various transmission customers 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. In October 2012, the FERC consolidated this complaint with the April 2012 formula rate change filing.

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 does not materially increase 2014 transmission revenues.

In June 2014, PSCo and its transmission customers reached a settlement in principle to resolve the ROE issue in the transmission rate filing and complaint. The settlement was filed in September 2014, and in October 2014, the FERC ALJ granted PSCo a motion to place interim rates into effect using the settlement ROE beginning Oct. 1, 2014. The FERC approved the settlement in October 2014, providing a 9.72 percent ROE effective retroactive to July 1, 2012 for the PSCo transmission formula rate. PSCo recorded a current liability for the refund obligation based on the settlement terms as of Sept. 30, 2014.

Production Formula Rate ROE Complaint — In August 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 production sales formula rates effective Sept. 1, 2013. In June 2014, PSCo and its wholesale customers reached a settlement in principle to resolve the complaint along with the pending transmission formula rate ROE matters. The settlement was filed in September 2014, and in October 2014, the FERC ALJ granted PSCo a motion to place interim rates into effect using the settlement ROE beginning Oct. 1, 2014. The FERC approved the settlement in October 2014, providing a 9.72 percent ROE effective for the PSCo production formula rate. PSCo recorded a current liability for the refund obligation based on the settlement terms as Sept. 30, 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.

10

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 Sept. 30, 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 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) — Section 316(b) of 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. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. At Sept. 30, 2014, the estimated cost of compliance for PSCo did not have a material impact on the results of operations, financial position or cash flows.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.

Air

EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. PSCo is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at PSCo’s power plants.

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Dec. 1, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in Colorado. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

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GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects 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.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at PSCo’s power plants.

Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. 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 (PM) 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 $360.5 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates.

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 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. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. On Oct. 6, 2014, the Court granted the EPA’s request and vacated the current briefing schedule. The EPA must provide a status update to the Court within 30 days.

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.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where PSCo operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In August 2014, EPA issued its proposed designations, which did not include areas in any states in which PSCo operates. The EPA is expected to finalize its designation of non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made.

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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 Court of Appeals (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.

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 contested the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC. PSCo filed a brief answering the City of Seattle’s exception. This matter is now pending a decision by the FERC.

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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, notwithstanding 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 Sept. 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250
Amount outstanding at period end	11			—
Average amount outstanding	10			0.1
Maximum amount outstanding	97			12
Weighted average interest rate, computed on a daily basis	0.25		%	0.36		%
Weighted average interest rate at period end	0.24			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, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	700		$	700
Amount outstanding at period end	253			—
Average amount outstanding	225			38
Maximum amount outstanding	315			332
Weighted average interest rate, computed on a daily basis	0.28		%	0.34		%
Weighted average interest rate at period end	0.28			N/A

Letters of Credit— PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Sept. 30, 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 line of credit 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, 2014, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	259.5	$	440.5

^(a)  Credit facility has been amended to expire in October 2019.

^(b)  Includes outstanding commercial paper and letters of credit.

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All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at Sept. 30, 2014 and Dec. 31, 2013.

Amended Credit Agreement —On Oct. 14, 2014, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an extension of maturity from July 2017 to October 2019. The borrowing limit for PSCo remained at $700 million. The Eurodollar borrowing margin on the line of credit ranges from 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fee, calculated on the unused portion of the line of credit, ranges from 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

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

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.

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.

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At Sept. 30, 2014, accumulated other comprehensive losses related to interest rate derivatives included $0.3 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, 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 and nine months ended Sept. 30, 2014 and 2013.

At Sept. 30, 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 Sept. 30, 2014 and Dec. 31, 2013:

(Amounts in Thousands)(a)(b)	Sept. 30, 2014	Dec. 31, 2013
Megawatt hours of electricity	—	326
Million British thermal units of natural gas	11,520	6,398
Gallons of vehicle fuel	149	217

^(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.

The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 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	$	—		$	—		$	(184	)	(a)	$	—	$	—
Vehicle fuel and other commodity	(27		)	—			(7		)	(b)	—		—
Total	$	(27	)	$	—		$	(191	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—		$	(2,126	)	$	—			$	—	$	(209	)	(c)
Total	$	—		$	(2,126	)	$	—			$	—	$	(209	)

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	Nine Months Ended Sept. 30, 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	$	—		$	—	$	(546	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(24		)	—		(27		)	(b)	—				—
Total	$	(24	)	$	—	$	(573	)		$	—			$	—
Other derivative instruments
Natural gas commodity	$	—		$	5,784	$	—			$	(8,579	)	(d)	$	(4,589	)	(d)
Total	$	—		$	5,784	$	—			$	(8,579	)		$	(4,589	)

	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 Losses 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	(c)
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	(d)	$	(216	)	(c)
Total	$	—		$	(4,896	)	$	—			$	7		$	(216	)

^(a)  Recorded to interest charges.

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

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

^(d)  Amounts for the nine months ended Sept. 30, 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 nine months ended Sept. 30, 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 and nine months ended Sept. 30, 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.

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, 2014, six of PSCo’s 10 most significant counterparties, comprising $25.5 million or 31 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 four significant counterparties, comprising $31.1 million or 38 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 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. At Sept. 30, 2014, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of PSCo were downgraded below investment grade. If the credit ratings of PSCo were downgraded below investment grade at Dec. 31, 2013, derivative instruments reflected in a $1.4 million gross liability position on the consolidated balance sheets 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 $1.4 million. At Sept. 30, 2014 and Dec. 31, 2013, there was no collateral posted on these specific contracts.

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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, 2014 and Dec. 31, 2013.

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, 2014:

	Sept. 30, 2014
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	2	$	—	$	2	$	(1	)	$	1
Other derivative instruments:
Natural gas commodity	—		5,524		—		5,524		(74		)	5,450
Total current derivative assets	$	—	$	5,526	$	—	$	5,526	$	(75	)	5,451
PPAs (a)												1,715
Current derivative instruments												$	7,166
Noncurrent derivative assets
PPAs (a)												5,605
Noncurrent derivative instruments												$	5,605
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	1	$	—	$	1	$	(1	)	$	—
Other derivative instruments:
Natural gas commodity	—		74		—		74		(74		)	—
Total current derivative liabilities	$	—	$	75	$	—	$	75	$	(75	)	—
PPAs (a)												5,190
Current derivative instruments												$	5,190
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	2	$	—	$	2	$	—		$	2
Other derivative instruments:
Natural gas commodity	—		71		—		71		—			71
Total noncurrent derivative liabilities	$	—	$	73	$	—	$	73	$	—		73
PPAs (a)												19,473
Noncurrent derivative instruments												$	19,546

^(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 Sept. 30, 2014. At Sept. 30, 2014, derivative assets and liabilities include no obligations to return cash collateral 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						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							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 and nine months ended Sept. 30, 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 and nine months ended Sept. 30, 2014 and 2013.

Fair Value of Long-Term Debt

As of Sept. 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,891,905	$	4,192,694	$	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 Sept. 30, 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 Sept. 30					Nine Months Ended Sept. 30
(Thousands of Dollars)	2014		2013			2014			2013
Interest income	$	729	$	713		$	1,375		$	2,470
Other nonoperating income	573		667			2,448			2,186
Insurance policy income (expense)	418		(434		)	(394		)	(811		)
Other income, net	$	1,720	$	946		$	3,429		$	3,845

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, transmits and distributes electricity primarily in portions of 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 primarily 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 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, 2014
Operating revenues (a)(b)	$	881,102	$	159,808	$	8,201	$	—		$	1,049,111
Intersegment revenues	95		29		—		(124		)	—
Total revenues	$	881,197	$	159,837	$	8,201	$	(124	)	$	1,049,111
Net income	$	139,751	$	7,235	$	7,173	$	—		$	154,159

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2013
Operating revenues (a)(b)	$	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

^(a)    Operating revenues include $2 million of affiliate electric revenue for the three months ended Sept. 30, 2014 and 2013.

^(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended Sept. 30, 2014 and 2013.

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2014
Operating revenues (a)(b)	$	2,376,935	$	839,332	$	30,091	$	—		$	3,246,358
Intersegment revenues	254		137		—		(391		)	—
Total revenues	$	2,377,189	$	839,469	$	30,091	$	(391	)	$	3,246,358
Net income	$	289,460	$	56,230	$	16,664	$	—		$	362,354

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2013
Operating revenues (a)(b)	$	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

^(a)    Operating revenues include $8 million and $6 million of affiliate electric revenue for the nine months ended Sept. 30, 2014 and 2013, respectively.

^(b)    Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2014 and 2013.

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30
	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			10,855			1,609			3,490
Net benefit cost (credit) recognized for financial reporting	$	9,327		$	12,476		$	(1,102	)	$	1,887

	Nine Months Ended Sept. 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	17,955		$	18,905		$	1,436		$	2,409
Interest cost	39,957			34,620			17,778			17,802
Expected return on plan assets	(53,031		)	(47,865		)	(22,661		)	(21,921		)
Amortization of transition obligation	—			—			—			588
Amortization of prior service credit	(2,319		)	(798		)	(4,685		)	(3,687		)
Amortization of net loss	25,419			32,563			4,826			10,469
Net benefit cost (credit) recognized for financial reporting	$	27,981		$	37,425		$	(3,306	)	$	5,660

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.

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12. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended Sept. 30, 2014			Three Months Ended Sept. 30, 2013
Accumulated other comprehensive loss at July 1	$	(23,573	)	$	(23,120	)
Other comprehensive (loss) income before reclassifications	(17		)	11
Gains reclassified from net accumulated other comprehensive loss	(119		)	(119		)
Net current period other comprehensive loss	(136		)	(108		)
Accumulated other comprehensive loss at Sept. 30	$	(23,709	)	$	(23,228	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2014			Nine Months Ended Sept. 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(23,338	)	$	(22,871	)
Other comprehensive loss before reclassifications	(15		)	(2		)
Gains reclassified from net accumulated other comprehensive loss	(356		)	(355		)
Net current period other comprehensive loss	(371		)	(357		)
Accumulated other comprehensive loss at Sept. 30	$	(23,709	)	$	(23,228	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2014				Three Months Ended Sept. 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(184	)	(a)	$	(184	)	(a)
Vehicle fuel derivatives	(7		)	(b)	(11		)	(b)
Total, pre-tax	(191		)		(195		)
Tax expense	72				76
Total amounts reclassified, net of tax	$	(119	)		$	(119	)

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2014				Nine Months Ended Sept. 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(546	)	(a)	$	(546	)	(a)
Vehicle fuel derivatives	(27		)	(b)	(30		)	(b)
Total, pre-tax	(573		)		(576		)
Tax expense	217				221
Total amounts reclassified, net of tax	$	(356	)		$	(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).

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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. 30, 2014.

Results of Operations

PSCo’s net income was approximately $362.4 million for the nine months ended Sept. 30, 2014, compared with approximately $380.2 million for the same period in 2013. Increases in electric and natural gas rates, higher allowance for funds used during construction (AFUDC), weather-normalized sales growth (which is adjusted against a 30-year average of actual weather conditions) and lower O&M expenses were offset by higher property taxes, depreciation, accruals associated with the electric earnings test refund obligations and the unfavorable impact of 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 minimal impact on electric margin. The following table details the electric revenues and margin:

	Nine Months Ended Sept. 30
(Millions of Dollars)	2014			2013
Electric revenues	$	2,377		$	2,368
Electric fuel and purchased power	(1,052		)	(998		)
Electric margin	$	1,325		$	1,370

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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)	2014 vs. 2013
Fuel and purchased power cost recovery	$	64
Retail sales growth, excluding weather impact	7
Estimated impact of weather	(29		)
Retail rate increase (net of estimated earnings test refund obligations)	(20		)
Trading, including REC sales	(17		)
Other, net	4
Total increase in electric revenues	$	9

Electric Margin

(Millions of Dollars)	2014 vs. 2013
Retail sales growth, excluding weather impact	$	7
Estimated impact of weather	(29		)
Retail rate increase (net of estimated earnings test refund obligations)	(20		)
Other, net	(3		)
Total decrease in electric margin	$	(45	)

Natural Gas Revenues and Margin

Total natural gas expense 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)	2014			2013
Natural gas revenues	$	839		$	731
Cost of natural gas sold and transported	(487		)	(403		)
Natural gas margin	$	352		$	328

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)	2014 vs. 2013
Purchased natural gas adjustment clause recovery	$	84
Retail rate increase, net of refund	16
Pipeline System Integrity Adjustment (PSIA) rider	10
Retail sales growth	5
Estimated impact of weather	(5		)
Other, net	(2		)
Total increase in natural gas revenues	$	108

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Natural Gas Margin

(Millions of Dollars)	2014 vs. 2013
Retail rate increase, net of refund	$	16
PSIA rider, partially offset in O&M expenses	10
Retail sales growth	5
Estimated impact of weather	(5		)
Other, net	(2		)
Total increase in natural gas margin	$	24

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses decreased $3.3 million, or 0.6 percent, for the nine months ended Sept. 30, 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 natural gas distribution expenses	$	6
Transmission costs	3
Plant generation costs	3
Employee benefits	(17		)
Other, net	2
Total decrease in O&M expenses	$	(3	)

• Lower employee benefits resulted primarily from decreases in pension expense, retiree medical costs and annual employee incentive accruals.

DSM Program Expenses— DSM program expenses increased $1.9 million, or 1.8 percent, for the nine months ended Sept. 30, 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.

Depreciation and Amortization— Depreciation and amortization expense increased $16.3 million, or 6.1 percent, for the nine months ended Sept. 30, 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 $18.3 million, or 17.6 percent, for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The increase is primarily due to higher property taxes.

AFUDC— AFUDC increased $20.3 million for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The increase is primarily due to construction related to the CACJA project.

Interest Charges —Interest charges increased $1.1 million, or 0.9 percent, for the nine months ended Sept. 30, 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 $16.2 million for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The decrease in income tax expense was primarily due to lower pre-tax earnings in 2014 and increased permanent plant-related adjustments in 2014. The ETR was 35.0 percent for the nine months ended Sept. 30, 2014 compared with 35.8 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. In September 2014, PSCo entered into a partial settlement agreement with the CPUC Staff that would grant a CPCN for the line. The Office of Consumer Counsel (OCC) has opposed the CPCN. A CPUC decision is expected by early 2015.

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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. On July 31, 2014, the ALJ issued a recommended decision accepting PSCo’s compliance plan with modifications. PSCo and several parties have filed exceptions to this recommended decision. A CPUC decision is anticipated in the fourth quarter of 2014.

Net Metering Standard — In conjunction with its 2014 RES compliance plan filing, PSCo proposed to track and quantify the system costs that are not avoided by distributed solar generation, which PSCo has defined as a “net metering incentive,” for purposes of equitably recovering costs between customers who participate in distributed generation and customers that do not. The CPUC has assigned the net metering issue to its own docket and established key dates to evaluate this matter. A CPUC decision is anticipated in the fourth quarter of 2014.

Solar*Connect Program — In April 2014, PSCo filed an application with the CPUC seeking approval for a program that would allow customers the option to purchase a portion or all of their electricity from a utility scale solar facility approximately 50 MW in size. Customer contracts under the program would run a minimum of one year. Several parties have opposed or offered modifications to the program. Hearings have been set for November 2014. A CPUC decision is anticipated in the fourth quarter of 2014.

Boulder, Colo. Municipalization — 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 May 2014, the Boulder City Council passed an ordinance to establish an electric utility. In June 2014, PSCo filed a complaint in the Boulder District Court seeking a declaratory ruling that this ordinance violates Boulder’s charter requirements. Subsequently, Boulder filed a motion to dismiss PSCo’s complaint, which is still pending.

The CPUC has previously ruled that it has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine certain system separation matters as well as what facilities need to be constructed to ensure reliable service. The CPUC has declared that it should make its determinations prior to any eminent domain actions. In January 2014, Boulder appealed this ruling to the Boulder District Court. PSCo and the CPUC filed briefs in June 2014 in opposition of Boulder’s appeal. This matter is currently pending.

Boulder sent PSCo an offer of $128 million for certain portions of PSCo’s transmission and distribution business, which includes Boulder and certain areas outside city limits. PSCo has notified Boulder that its offer has deficiencies related to property descriptions as well as other relevant information impacting the remainder of PSCo’s system. Under Colorado law, a condemning entity must pay the owner fair market value for the taking of and damages to the remainder of the property. In July 2014, Boulder filed a petition for condemnation in the Boulder District Court. PSCo filed a motion to dismiss the petition based upon the CPUC’s ruling that it must determine the appropriate system separations prior to Boulder filing its condemnation case. PSCo’s motion to dismiss is currently pending.

In August 2014, PSCo filed a petition with the FERC requesting an order requiring that Boulder’s attempt to acquire PSCo’s transmission and distribution facilities by condemnation requires prior FERC approval under the Federal Power Act. Boulder and The American Public Power Association opposed the petition in October 2014. This matter is currently pending FERC action.

If Boulder is allowed to proceed with its condemnation petition and were to succeed in the eminent domain proceeding, PSCo would 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.

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FERC Order, New ROE Policy — In June 2014, the FERC issued an order in an ROE complaint proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth (the prior FERC ROE methodology). In October 2014, the FERC made its final determination for incorporating the long term growth rate to be used together with a short term growth rate in its new ROE methodology. Several parties sought rehearing of the June 2014 order and therefore the new FERC policy may be subject to additional changes.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued a final ruling, 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. Various parties filed appeals of Order 1000 with the D.C. Circuit. In August 2014, the court denied all appeals and upheld Order 1000 in its entirety. The court indicated, however, that challenges to removal of federal ROFR provisions from individual contracts or tariffs could be considered in individual compliance filings.

In Order 1000, FERC instead required that the opportunity to build such projects would extend to competitive transmission developers. PSCo made its initial compliance filings to incorporate new provisions into their tariffs regarding regional planning and cost allocation. Subsequently, the FERC ruled on the initial regional compliance filings, directing further compliance changes. The PSCo regional compliance filings remain pending further action by the FERC.

Initial filings to address interregional planning and cost allocation requirements with other regions were made by PSCo and are pending initial action by the FERC.

The State of Colorado does not have legislation protecting ROFR rights for incumbent utilities.

Regional planning and cost allocation

PSCo submitted its FERC regional compliance filing in October 2012 proposing that it would join the WestConnect region, a consortium of FERC jurisdictional utilities in the Western Interconnection. In September 2013, PSCo and other WestConnect utilities submitted their updated regional compliance filings. In September 2014, the FERC issued an order partially accepting and partially rejecting the September 2013 compliance filings. FERC ordered additional compliance filings within 60 days. PSCo and other WestConnect utilities requested rehearing of the September 2014 FERC order and plan to submit additional compliance filings in November 2014.

Interregional planning and cost allocation

PSCo and other WestConnect members’ interregional compliance filings were submitted in May 2013 and are pending initial FERC action.

The WestConnect members proposed that the Order 1000 regional and interregional compliance tariffs be effective prospectively after the final FERC orders, and not earlier than Jan. 1, 2015.

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. PSCo is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

NERC Physical Security Requirements — In July 2014, the FERC issued a notice of proposed rulemaking generally proposing to adopt NERC’s proposed CIP standard related to physical security for bulk electric system facilities. However, the FERC proposed a modification to the standard that would allow certain governmental authorities, including FERC, to revise an entity’s list of critical facilities. PSCo expects prompt action by FERC to finalize the rule with a likely effective date in 2015. PSCo is currently in the process of evaluating and identifying the critical facilities impacted to better determine the cost of protections necessary to meet the standard. The additional cost for compliance is anticipated to be recoverable through rates.

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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, 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 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

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.

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, 2013, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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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. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03280)).
10.01*	Amended and Restated Credit Agreement, dated as of Oct. 14, 2014 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.03 to Form 8-K, dated Oct. 14, 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	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, 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 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. 3, 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

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