10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended Sept. 30, 2015

or

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

Commission File Number: 001-3280

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

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

(303) 571-7511

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

Class	Outstanding at Oct. 30, 2015
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.

1

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 4 —	Controls and Procedures	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	30
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
	2015			2014			2015			2014
Operating revenues
Electric	$	884,305		$	881,102		$	2,385,297		$	2,376,935
Natural gas	151,553			159,808			716,731			839,332
Steam and other	8,846			8,201			30,647			30,091
Total operating revenues	1,044,704			1,049,111			3,132,675			3,246,358
Operating expenses
Electric fuel and purchased power	311,347			368,860			930,107			1,052,400
Cost of natural gas sold and transported	44,953			60,073			354,825			487,159
Cost of sales — steam and other	3,596			3,538			12,938			11,951
Operating and maintenance expenses	186,379			185,510			560,021			549,935
Demand side management program expenses	33,040			36,120			96,622			105,993
Depreciation and amortization	104,228			95,075			305,517			283,506
Taxes (other than income taxes)	45,987			38,862			146,895			122,467
Total operating expenses	729,530			788,038			2,406,925			2,613,411
Operating income	315,174			261,073			725,750			632,947
Other income, net	1,222			1,720			2,674			3,429
Allowance for funds used during construction — equity	3,958			12,315			10,155			36,697
Interest charges and financing costs
Interest charges — includes other financing costs of $1,611, $1,546, $4,671 and     $4,798, respectively	44,875			42,540			131,859			128,941
Allowance for funds used during construction — debt	(1,467		)	(4,564		)	(3,890		)	(13,584		)
Total interest charges and financing costs	43,408			37,976			127,969			115,357
Income before income taxes	276,946			237,132			610,610			557,716
Income taxes	103,865			82,973			228,063			195,362
Net income	$	173,081		$	154,159		$	382,547		$	362,354

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
	2015			2014			2015			2014
Net income	$	173,081		$	154,159		$	382,547		$	362,354
Other comprehensive income (loss)
Derivative instruments:
Net fair value decrease, net of tax of $(12), $(10), $(10), and $(9), respectively	(17		)	(17		)	(14		)	(15		)
Reclassification of losses (gains) to net income, net of tax of $5, $(72), $(123) and $(217),    respectively	19			(119		)	(192		)	(356		)
Other comprehensive income (loss)	2			(136		)	(206		)	(371		)
Comprehensive income	$	173,083		$	154,023		$	382,341		$	361,983

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
	2015			2014
Operating activities
Net income	$	382,547		$	362,354
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	309,048			287,141
Demand side management program amortization	2,776			3,309
Deferred income taxes	185,212			120,585
Amortization of investment tax credits	(2,200		)	(2,202		)
Allowance for equity funds used during construction	(10,155		)	(36,697		)
Net realized and unrealized hedging and derivative transactions	3,255			(6,946		)
Changes in operating assets and liabilities:
Accounts receivable	61,044			55,070
Accrued unbilled revenues	92,819			58,758
Inventories	1,215			(26,409		)
Prepayments and other	75,488			1,001
Accounts payable	(78,610		)	(86,984		)
Net regulatory assets and liabilities	43,125			110,692
Other current liabilities	(36,587		)	(43,323		)
Pension and other employee benefit obligations	(22,653		)	(37,769		)
Change in other noncurrent assets	2,273			5,353
Change in other noncurrent liabilities	(30,667		)	(15,355		)
Net cash provided by operating activities	977,930			748,578
Investing activities
Utility capital/construction expenditures	(668,381		)	(832,270		)
Allowance for equity funds used during construction	10,155			36,697
Investments in utility money pool arrangement	(150,300		)	(587,000		)
Repayments from utility money pool arrangement	166,300			659,000
Net cash used in investing activities	(642,226		)	(723,573		)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(382,000		)	253,000
Borrowings under utility money pool arrangement	67,000			303,000
Repayments under utility money pool arrangement	(67,000		)	(292,000		)
Proceeds from issuance of long-term debt	246,826			295,601
Repayments of long-term debt	—			(275,000		)
Capital contributions from parent	73,718			35,486
Dividends paid to parent	(247,174		)	(355,547		)
Net cash used in financing activities	(308,630		)	(35,460		)
Net change in cash and cash equivalents	27,074			(10,455		)
Cash and cash equivalents at beginning of period	7,635			21,089
Cash and cash equivalents at end of period	$	34,709		$	10,634
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(145,569	)	$	(136,045	)
Cash received (paid) for income taxes, net	38,349			(67,717		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	104,965		$	125,498

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, 2015			Dec. 31, 2014
Assets
Current assets
Cash and cash equivalents	$	34,709		$	7,635
Accounts receivable, net	256,571			322,885
Accounts receivable from affiliates	11,592			50,842
Investments in utility money pool arrangement	—			16,000
Accrued unbilled revenues	201,230			294,049
Inventories	237,764			238,979
Regulatory assets	88,275			120,120
Deferred income taxes	95,539			64,587
Derivative instruments	1,715			1,731
Prepaid taxes	17,354			90,365
Prepayments and other	21,502			23,979
Total current assets	966,251			1,231,172
Property, plant and equipment, net	11,966,302			11,626,956
Other assets
Regulatory assets	886,072			903,973
Derivative instruments	3,890			5,176
Other	46,864			48,506
Total other assets	936,826			957,655
Total assets	$	13,869,379		$	13,815,783
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	8,921		$	8,178
Short-term debt	—			382,000
Accounts payable	325,178			425,133
Accounts payable to affiliates	33,430			46,736
Regulatory liabilities	152,901			134,459
Taxes accrued	132,251			159,470
Accrued interest	27,043			48,409
Dividends payable to parent	83,672			83,652
Derivative instruments	6,437			5,774
Other	80,419			72,002
Total current liabilities	850,252			1,365,813
Deferred credits and other liabilities
Deferred income taxes	2,658,792			2,437,641
Deferred investment tax credits	34,072			36,273
Regulatory liabilities	450,014			464,421
Asset retirement obligations	239,643			225,296
Derivative instruments	14,317			18,257
Customer advances	199,799			229,990
Pension and employee benefit obligations	179,276			202,031
Other	67,871			68,171
Total deferred credits and other liabilities	3,843,784			3,682,080
Commitments and contingencies
Capitalization
Long-term debt	4,125,159			3,882,051
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively	—			—
Additional paid in capital	3,551,986			3,522,788
Retained earnings	1,522,282			1,386,929
Accumulated other comprehensive loss	(24,084		)	(23,878		)
Total common stockholder’s equity	5,050,184			4,885,839
Total liabilities and equity	$	13,869,379		$	13,815,783

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, 2015 and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2015 and 2014; and its cash flows for the nine months endedSept. 30, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2015 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, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2014. 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, 2014, filed with the SEC on Feb. 20, 2015. 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, 2014, 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 (FASB) 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. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. PSCo does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, PSCo does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, PSCo does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

7

3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	277,134		$	346,007
Less allowance for bad debts	(20,563		)	(23,122		)
	$	256,571		$	322,885

(Thousands of Dollars)	Sept. 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	58,532	$	55,491
Fuel	90,135		80,963
Natural gas	89,097		102,525
	$	237,764	$	238,979

(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	11,689,760		$	10,927,867
Natural gas plant	3,341,157			3,210,242
Common and other property	823,239			827,708
Plant to be retired (a)	42,336			71,534
Construction work in progress	486,133			828,620
Total property, plant and equipment	16,382,625			15,865,971
Less accumulated depreciation	(4,416,323		)	(4,239,015		)
	$	11,966,302		$	11,626,956

^(a)  PSCo’s Cherokee Unit 3 was retired in August 2015.  In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC).  Amounts are presented net of accumulated depreciation.

4. Income Taxes

Except to the extent noted below, Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, 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. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Sept. 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $13 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. PSCo is not expected to accrue any income tax expense related to this adjustment. As of Sept. 30, 2015, the IRS had begun the appeals process; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009-2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2015, 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.

8

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

(Millions of Dollars)	Sept. 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.9	$	1.9
Unrecognized tax benefit — Temporary tax positions	13.8		10.0
Total unrecognized tax benefit	$	15.7	$	11.9

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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(6.5	)	$	(3.9	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process and audit progress 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, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2015 or Dec. 31, 2014.

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, 2014 and in Note 5 to the consolidated financial statements included in PSCo’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — CPUC

Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million, or 3.5 percent, in 2015, with subsequent step increases of $7.6 million, or 0.7 percent, in 2016 and $18.1 million, or 1.5 percent, in 2017.

The request is based on a historic test year (HTY) ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan and an equity ratio of 56 percent. The rate case requests a return on equity (ROE) of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017.

PSCo also proposed a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and implementation of an earnings test for 2016 through 2017.

In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. The following table summarizes the request:

(Millions of Dollars)	2015			2016 Step		2017 Step
Total base rate increase	$	40.5		$	7.6	$	18.1
Incremental PSIA rider revenues	(0.1		)	21.7		21.2
Total revenue impact	$	40.4		$	29.3	$	39.3

9

In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC) issued their 2015 base rate recommendations. The following table reflects the current positions of Staff and OCC:

(Millions of Dollars)	Staff			OCC
PSCo’s filed 2015 base rate request	$	40.5		$	40.5
ROE	(12.8		)	(13.7		)
Capital structure and cost of debt	(12.8		)	(4.8		)
Cherokee pipeline adjustment	(11.2		)	4.8
Move to 2014 HTY	(10.5		)	(16.4		)
Operating and maintenance (O&M) expenses	(3.5		)	(2.7		)
Other, net	(4.4		)	(1.9		)
Total adjustments	$	(55.2	)	$	(34.7	)
Recommended (decrease) increase	$	(14.7	)	$	5.8

The Staff’s recommendation for the PSIA rider is as follows:

(Millions of Dollars)	2016			2017
PSCo’s filed incremental PSIA request	$	21.7		$	21.2
Transfer PSIA O&M to base rates	(24.1		)	(2.0		)
ROE and capital structure	(8.2		)	(3.6		)
Transfer meter replacement program from base rates to PSIA	1.7			1.7
Total	$	(8.9	)	$	17.3

In July 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows:

(Millions of Dollars)	2015			2016 Step		2017 Step
PSCo’s filed base rate request	$	40.5		$	7.6	$	18.1
Shift O&M expenses between PSIA and base rates	—			7.0		6.4
Rebuttal corrections and adjustments	—			—		(7.7		)
Total base rate request	$	40.5		$	14.6	$	16.8
Incremental PSIA rider revenues	(0.1		)	14.7		21.7
Total revenue impact from rebuttal	$	40.4		$	29.3	$	38.5

If PSCo’s revised request is accepted, PSIA revenue is projected to be $67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017.

Interim rates, subject to refund, were also implemented, effective Oct. 1, 2015, based on PSCo’s direct testimony. PSCo is expecting the ALJ’s Recommended Decision in November 2015. The final CPUC decision is expected no later than January 2016.

Annual Electric Earnings Test — In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test, in which PSCo shares with customers’ earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of Sept. 30, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test, based on annual forecasted information.

10

Electric, Purchased Gas and Resource Adjustment Clauses

Demand Side Management (DSM) and the Demand Side Management Cost Adjustment (DSMCA) — The CPUC approved higher savings goals and a lower financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2015. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Savings goals were 384 gigawatt hours (GWh) in 2014 and are 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million. For the years 2015 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual earnings limit of $84.3 million.

In July 2015, the CPUC approved PSCo’s 2015-2016 DSM plan:

• A 2015 DSM electric budget of $81.6 million;

• A 2015 DSM gas budget of $13.1 million;

• A 2016 DSM electric budget of $78.7 million; and

• A 2016 DSM gas budget of $13.6 million.

6. Commitments and Contingencies

Except to the extent noted below and in Note 5 above, 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, 2014 and in Notes 5 and 6 to the consolidated financial statements included in PSCo's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.

Purchased Power Agreements (PPAs)

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

PSCo had approximately 1,802 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2015 and Dec. 31, 2014, 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

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 2015, the Environmental Protection Agency (EPA) issued a final 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. PSCo is currently reviewing the final rule and cannot predict, at this time, whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. PSCo believes that compliance costs would be recoverable through regulatory mechanisms.

Federal CWA Waters of the United States Rule —In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings.

11

Air

Green House Gas (GHG) Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90-day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which PSCo operates. Until PSCo has reviewed the final rule and has more information about state implementation plans, PSCo cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. PSCo believes that compliance costs will be recoverable through regulatory mechanisms.

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 natural gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The NSPS does 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. The final rule was published in October 2015. PSCo does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

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 was published in October 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 standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if PSCo were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, PSCo had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. In June 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. PSCo believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread 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 (SO₂), nitrous oxide (NO_x), and particulate matter emissions under BART and set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a SIP that included the Clean Air Clean Jobs Act (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 Hayden Unit 1 and Hayden Unit 2 will be placed into service in late 2015 and late 2016, respectively, at an estimated combined cost of $82.4 million. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

12

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 challenged 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. In October, 2014, the Court granted the EPA’s request and vacated the current briefing schedule. In May 2015, the EPA published its final rule which re-affirmed the approval of the State of Colorado’s BART determination for Comanche Units 1 and 2. The determination found that the controls currently installed on the units for NOx are BART. In July 2015, WildEarth Guardians filed a petition for review of the EPA's May 2015 final rule. In September 2015, in response to a motion filed by WildEarth Guardians and the EPA, the 10^th Circuit issued an order dismissing the case.

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

Implementation of the National Ambient Air Quality Standard (NAAQS) for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where PSCo operates power plants.  However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant.  The Pawnee plant recently installed an SO₂ scrubber to reduce SO₂ emissions. The Colorado Department of Health and Environment made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA's final decision is expected by summer 2016. 

If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months, designed to achieve the NAAQS within five years.

Revisions to the NAAQS for Ozone— In October 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In Colorado, the Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard. If not in attainment, impacted areas would study the sources of nonattainment and make emission reduction plans to attain the new standards. These plans would be due to the EPA in 2020. In conjunction with CACJA, PSCo has or plans to shut down coal-fired plants in the Denver area, has installed NOx controls on Pawnee and Hayden Unit 1 and will finish installing NOx controls on Hayden Unit 2 in 2016. The final designation of nonattainment areas will be made in late 2017 based on air quality data years 2014-2016. PSCo cannot evaluate the impacts of this ruling in Colorado until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that, should NOx control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

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.

13

Employment, Tort and Commercial Litigation

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

Notwithstanding its petition for review, 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. This matter is now pending a decision by the FERC.

In addition, on Feb. 17, 2015, the U.S. Court of Appeals of the Ninth Circuit directed parties to the pending FERC proceeding to submit briefs addressing, among other issues, the petition for review filed by the City of Seattle seeking review of FERC’s order on remand. Parties are directed to address whether FERC’s order properly established the scope for the hearing that concluded in October 2013. Respondent-intervenors, including PSCo jointly with others, submitted briefs on May 8, 2015. Oral argument was held on June 16, 2015, and the matter is now pending before the Ninth Circuit.

14

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 PRPs. No accrual has been recorded for this matter.

7. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2015		Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		4
Maximum amount outstanding	8		97
Weighted average interest rate, computed on a daily basis	N/A		0.25		%
Weighted average interest rate at period end	N/A		N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	700		$	700
Amount outstanding at period end	—			382
Average amount outstanding	8			167
Maximum amount outstanding	67			393
Weighted average interest rate, computed on a daily basis	0.43		%	0.31		%
Weighted average interest rate at period end	N/A			0.65

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, 2015 and Dec. 31, 2014, there were $5 million and $6 million, respectively, of letters of credit outstanding 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, 2015, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700	$	5	$	695

^(a)    This credit facility expires in October 2019.

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

15

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, 2015 and Dec. 31, 2014.

Long-Term Borrowings

In May 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025.

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.

At Sept. 30, 2015, accumulated other comprehensive losses related to interest rate derivatives included $1.0 million of net losses 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, as applicable.

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.

16

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, 2015, 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 endedSept. 30, 2015 and 2014.

At Sept. 30, 2015, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses 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, 2015 and Dec. 31, 2014:

(Amounts in Thousands)(a)(b)	Sept. 30, 2015	Dec. 31, 2014
Million British thermal units of natural gas	9,621	735
Gallons of vehicle fuel	79	127

^(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, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 2015
	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	$	—		$	—		$	9	(a)	$	—	$	—
Vehicle fuel and other commodity	(29		)	—			15		(b)	—		—
Total	$	(29	)	$	—		$	24		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—		$	(2,140	)	$	—		$	—	$	(405	)	(d)
Total	$	—		$	(2,140	)	$	—		$	—	$	(405	)

17

	Nine Months Ended Sept. 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains)Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(353	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(24		)	—			38			(b)	—			—
Total	$	(24	)	$	—		$	(315	)		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—		$	191		(c)
Natural gas commodity	—			(2,496		)	—				5,460		(d)	(5,925		)	(d)
Total	$	—		$	(2,496	)	$	—			$	5,460		$	(5,734	)

	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	)

18

	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	)

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

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

^(d)  Amounts for the three and nine months endedSept. 30, 2015 included $0.4 million and $0.5 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Losses for the nine months endedSept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months endedSept. 30, 2015 and 2014 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, 2015 and 2014. 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, 2015, four of PSCo’s 10 most significant counterparties, comprising $5.6 million or 10 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Five of the 10 most significant counterparties, comprising $23.9 million or 42 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. Another of these significant counterparties, comprising $5.7 million or 10 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. 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, 2015 and Dec. 31, 2014, there were no derivative instruments with contract provisions that required the posting of collateral or settlement of the contracts.

19

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, 2015 and Dec. 31, 2014.

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, 2015:

	Sept. 30, 2015
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	1,668	$	—	$	1,668	$	(1,668	)	$	—
Total current derivative assets	$	—	$	1,668	$	—	$	1,668	$	(1,668	)	—
PPAs (a)												1,715
Current derivative instruments												$	1,715
Noncurrent derivative assets
PPAs (a)												$	3,890
Noncurrent derivative instruments												$	3,890
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	70	$	—	$	70	$	—		$	70
Other derivative instruments:
Natural gas commodity	—		2,000		—		2,000		(1,668		)	332
Other commodity	—		844		—		844		—			844
Total current derivative liabilities	$	—	$	2,914	$	—	$	2,914	$	(1,668	)	1,246
PPAs (a)												5,191
Current derivative instruments												$	6,437
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	16	$	—	$	16	$	—		$	16
Other derivative instruments:
Other commodity	—		18		—		18		—			18
Total noncurrent derivative liabilities	$	—	$	34	$	—	$	34	$	—		34
PPAs (a)												14,283
Noncurrent derivative instruments												$	14,317

^(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, 2015. At Sept. 30, 2015, derivative assets and liabilities include no obligations to return cash collateral or 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.

20

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, 2014:

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	33	$	—	$	33	$	(18	)	$	15
Total current derivative assets	$	—	$	33	$	—	$	33	$	(18	)	15
PPAs (a)												1,716
Current derivative instruments												$	1,731
Noncurrent derivative assets
PPAs (a)												$	5,176
Noncurrent derivative instruments												$	5,176
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	53	$	—	$	53	$	—		$	53
Other derivative instruments:
Natural gas commodity	—		548		—		548		(18		)	530
Total current derivative liabilities	$	—	$	601	$	—	$	601	$	(18	)	583
PPAs (a)												5,191
Current derivative instruments												$	5,774
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	46	$	—	$	46	$	—		$	46
Other derivative instruments:
Natural gas commodity	—		35		—		35		—			35
Total noncurrent derivative liabilities	$	—	$	81	$	—	$	81	$	—		81
PPAs (a)												18,176
Noncurrent derivative instruments												$	18,257

^(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, 2014. At Dec. 31, 2014, derivative assets and liabilities included no obligations to return cash collateral or 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 endedSept. 30, 2015 and 2014.

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, 2015 and 2014.

Fair Value of Long-Term Debt

As of Sept. 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,134,080	$	4,429,648	$	3,890,229	$	4,328,968

21

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, 2015 and Dec. 31, 2014, 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)	2015		2014		2015		2014
Interest income	$	162	$	729	$	537	$	1,375
Other nonoperating income	607		573		1,904		2,448
Insurance policy income (expense)	453		418		233		(394		)
Other income, net	$	1,222	$	1,720	$	2,674	$	3,429

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, 2015
Operating revenues (a)(b)	$	884,305	$	151,553	$	8,846	$	—		$	1,044,704
Intersegment revenues	65		9		—		(74		)	—
Total revenues	$	884,370	$	151,562	$	8,846	$	(74	)	$	1,044,704
Net income	$	167,931	$	4,548	$	602	$	—		$	173,081

22

(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

^(a)    Operating revenues include $2 million of affiliate electric revenue for the three months ended Sept. 30, 2015and 2014.

^(b)    Operating revenues include $2 million and $1 million of other affiliate revenue for the three months ended Sept. 30, 2015 and 2014, respectively.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2015
Operating revenues (a)(b)	$	2,385,297	$	716,731	$	30,647	$	—		$	3,132,675
Intersegment revenues	222		43		—		(265		)	—
Total revenues	$	2,385,519	$	716,774	$	30,647	$	(265	)	$	3,132,675
Net income	$	330,276	$	51,784	$	487	$	—		$	382,547

(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

^(a)    Operating revenues include $6 million and $8 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014, respectively.

^(b)    Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2015 and 2014.

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,065		$	5,985		$	232		$	479
Interest cost	12,714			13,319			4,375			5,926
Expected return on plan assets	(18,147		)	(17,677		)	(5,951		)	(7,554		)
Amortization of prior service credit	(784		)	(773		)	(1,562		)	(1,562		)
Amortization of net loss	9,094			8,473			618			1,609
Net periodic benefit cost (credit)	9,942			9,327			(2,288		)	(1,102		)
Cost not recognized due to the effects of regulation	(366		)	—			—			—
Net benefit cost (credit) recognized for financial reporting	$	9,576		$	9,327		$	(2,288	)	$	(1,102	)

23

	Nine Months Ended Sept. 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	21,195		$	17,955		$	696		$	1,436
Interest cost	38,142			39,957			13,124			17,778
Expected return on plan assets	(54,442		)	(53,031		)	(17,852		)	(22,661		)
Amortization of prior service credit	(2,352		)	(2,319		)	(4,686		)	(4,685		)
Amortization of net loss	27,282			25,419			1,856			4,826
Net periodic benefit cost (credit)	29,825			27,981			(6,862		)	(3,306		)
Cost not recognized due to the effects of regulation	(1,098		)	—			—			—
Net benefit cost (credit) recognized for financial reporting	$	28,727		$	27,981		$	(6,862	)	$	(3,306	)

In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $20.0 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2015.

12. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended Sept. 30, 2015			Three Months Ended Sept. 30, 2014
Accumulated other comprehensive loss at July 1	$	(24,086	)	$	(23,573	)
Other comprehensive loss before reclassifications	(17		)	(17		)
Losses (gains) reclassified from net accumulated other comprehensive loss	19			(119		)
Net current period other comprehensive income (loss)	2			(136		)
Accumulated other comprehensive loss at Sept. 30	$	(24,084	)	$	(23,709	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2015			Nine Months Ended Sept. 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)	$	(23,338	)
Other comprehensive loss before reclassifications	(14		)	(15		)
Gains reclassified from net accumulated other comprehensive loss	(192		)	(356		)
Net current period other comprehensive loss	(206		)	(371		)
Accumulated other comprehensive loss at Sept. 30	$	(24,084	)	$	(23,709	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2015				Three Months Ended Sept. 30, 2014
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	9		(a)	$	(184	)	(a)
Vehicle fuel derivatives	15			(b)	(7		)	(b)
Total, pre-tax	24				(191		)
Tax expense	(5		)		72
Total amounts reclassified, net of tax	$	19			$	(119	)

24

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2015				Nine Months Ended Sept. 30, 2014
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(353	)	(a)	$	(546	)	(a)
Vehicle fuel derivatives	38			(b)	(27		)	(b)
Total, pre-tax	(315		)		(573		)
Tax expense	123				217
Total amounts reclassified, net of tax	$	(192	)		$	(356	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein 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 expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including PSCo's Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2014 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: 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 a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; actions of credit rating agencies; 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; cyber security threats and data security breaches; 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; outcomes of regulatory proceedings; availability of cost of capital; and employee work force factors.

Results of Operations

PSCo’s net income was approximately $382.5 million for the nine months ended Sept. 30, 2015, compared with approximately $362.4 million for the same period in 2014. Higher revenue primarily due to the CACJA rider (partially offset by an electric base rate decrease), lower estimated electric earnings test refunds and the impact of favorable weather were partially offset by lower allowance for funds used during construction (AFUDC), higher property taxes, depreciation and O&M expenses.

25

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)	2015			2014
Electric revenues	$	2,385		$	2,377
Electric fuel and purchased power	(930		)	(1,052		)
Electric margin	$	1,455		$	1,325

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)	2015 vs. 2014
Non-fuel riders (a)	$	74
Earnings test refunds	61
Firm wholesale	10
Estimated impact of weather	10
Fuel and purchased power cost recovery	(110		)
Retail rate decrease	(28		)
Trading	(12		)
Other, net	3
Total increase in electric revenues	$	8

Electric Margin

(Millions of Dollars)	2015 vs. 2014
Non-fuel riders (a)	$	74
Earnings test refunds	61
Firm wholesale	10
Estimated impact of weather	10
Retail rate decrease	(28		)
Other, net	3
Total increase in electric margin	$	130

^(a) Increase relates primarily to the new CACJA rider, effective Jan. 1, 2015. This amount positively impacted revenues and more than offset the base rate decrease.

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)	2015			2014
Natural gas revenues	$	717		$	839
Cost of natural gas sold and transported	(355		)	(487		)
Natural gas margin	$	362		$	352

26

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)	2015 vs. 2014
Purchased natural gas adjustment clause recovery	$	(133	)
Estimated impact of weather	(6		)
DSM program revenues (offset by expenses)	(3		)
Non-fuel riders, partially offset by expenses	16
Gas transport - Cherokee pipeline	4
Total decrease in natural gas revenues	$	(122	)

Natural Gas Margin

(Millions of Dollars)	2015 vs. 2014
Non-fuel riders, partially offset by expenses	$	16
Gas transport - Cherokee pipeline	4
Estimated impact of weather	(6		)
DSM program revenues (offset by expenses)	(3		)
Other, net	(1		)
Total increase in natural gas margin	$	10

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased $10.1 million, or 1.8 percent, for the nine months ended Sept. 30, 2015 compared with the same period in 2014. O&M expenses were higher, primarily due to the timing of planned maintenance and overhauls at our generation facilities. The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2015 vs. 2014
Plant generation costs	$	4
Employee benefits	4
Other, net	2
Total increase in O&M expenses	$	10

DSM Program Expenses— DSM program expenses decreased $9.4 million, or 8.8 percent, for the nine months ended Sept. 30, 2015 compared with the same period in 2014. The decrease was primarily attributable to lower electric and gas recovery rates in addition to lower gas volumes.

Depreciation and Amortization— Depreciation and amortization expense increased $22.0 million, or 7.8 percent, for the nine months ended Sept. 30, 2015 compared with the same period for 2014. The increase is primarily attributable to normal system expansion and the in-servicing of Cherokee Units 5, 6 and 7 in July 2015.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased $24.4 million, or 19.9 percent, for the nine months ended Sept. 30, 2015 compared with the same period in 2014. The increase is primarily due to higher property taxes.

AFUDC— AFUDC decreased $36.2 million for the nine months ended Sept. 30, 2015 compared with the same period in 2014. The decrease was primarily due to the implementation of the CACJA rider on Jan. 1, 2015, facilitating earlier and alternative recovery of construction costs.

Income Taxes — Income tax expense increased $32.7 million for the nine months ended Sept. 30, 2015 compared with the same period in 2014. The increase in income tax expense was primarily due to higher pretax earnings in 2015 and decreased permanent plant-related adjustments in 2015. The ETR was 37.4 percent for the nine months ended Sept. 30, 2015 compared with 35.0 percent for the same period in 2014. The higher ETR was primarily due to the same adjustments mentioned above.

27

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1. of PSCo's Annual Report on Form 10-K for the year ended Dec. 31, 2014, and Public Utility Regulation included in Item 2. of PSCo's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

Net Metering Standard — PSCo had previously 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. The CPUC assigned the net metering issue to its own docket and conducted a series of panel discussions to gain a better understanding of net metering issues. In the third quarter, the CPUC closed the net metering docket, concluding that they would not make any changes to the net metering policies. The decision does not preclude the PSCo from filing changes to the PSCo’s net metering practices in the future.

Boulder, Colo. Municipalization — PSCo’s franchise agreement with the City of Boulder (Boulder) expired in December 2010. In November 2011, a ballot measure was passed which authorized the formation and operation of a municipal 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 2013, the CPUC ruled that it has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine 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. In January 2015, the Boulder District Court affirmed the CPUC decision.

Boulder sent PSCo an offer of $128 million for certain portions of PSCo’s transmission and distribution business. PSCo has notified Boulder that its offer was deficient. 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 was granted in February 2015. This decision does not prevent Boulder from filing another condemnation petition if it obtains CPUC approval of its separation plan.

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. In December 2014, the FERC issued an order granting PSCo’s petition.

If Boulder proceeds with another 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.

In April 2015, Boulder issued a request for proposal for a partial requirements wholesale electric power supply agreement. Boulder indicated that the request for proposal was designed to elicit a wholesale power supply arrangement for a five-year term commencing on Jan. 1, 2018. Boulder has requested that PSCo consider different pricing structures and allow for Boulder to reduce demand over the term of the contract. In May 2015, PSCo sent Boulder a letter indicating its willingness to discuss a power supply arrangement with Boulder, but no formal offer was made.

In July 2015, Boulder filed an application with the CPUC requesting approval of Boulder’s proposed separation plan, seeking to take certain distribution assets of PSCo outside of the city limits but allowing PSCo to bill the customers for service. In August 2015, PSCo brought a Motion to Dismiss arguing Boulder's request was not permissible under Colorado law. The matter is now pending before the CPUC.

Cabin Creek Hydro Upgrade — PSCo filed a certificate of public convenience and necessity (CPCN) with the CPUC in May 2015 to upgrade the Cabin Creek Hydro facility. The upgrade is estimated to cost $89.2 million and will extend the life of the facility by 40 years as well as increase the maximum output by 36 MW. In August 2015, the CPUC granted the application for the upgrade.

28

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, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2014. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In March 2015, FERC upheld the new ROE methodology and denied rehearing. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC is not expected to issue orders in any of the litigated ROE complaint proceedings until 2016.

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, 2015, 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, 2014, 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.

29

Item 5 — OTHER INFORMATION

None.

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)).
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, 2015 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.

30

SIGNATURES

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

		Public Service Company of Colorado
Oct. 30, 2015	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

31

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: Oct. 30, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: Oct. 30, 2015

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Public Service Company of Colorado (PSCo) on Form 10-Q for the quarter ended Sept. 30, 2015, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of PSCo certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

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

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

Date: Oct. 30, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

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

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

1

EX-99.01

Exhibit 99.01

Public Service Company of Colorado Cautionary Factors

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

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

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

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

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

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

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

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

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

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

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

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

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

• Social attitudes regarding the utility and power industries;

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

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

• Risks associated with implementations of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in PSCo’s SEC filings, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2014, or in other publicly disseminated written documents.

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

XML

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 382,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000	250,000
Amount outstanding at period end	0	0
Average amount outstanding	0	4,000
Maximum amount outstanding	8,000	$ 97,000
Weighted average interest rate, computed on a daily basis (percentage)		0.25%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	700,000	$ 700,000
Amount outstanding at period end	0	382,000
Average amount outstanding	8,000	167,000
Maximum amount outstanding	$ 67,000	$ 393,000
Weighted average interest rate, computed on a daily basis (percentage)	0.43%	0.31%
Weighted average interest rate at period end (percentage)		0.65%

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,134,080	$ 3,890,229
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,429,648	$ 4,328,968

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Sep. 30, 2015		Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		$ 0		$ 0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,715		1,731
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3,890		5,176
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		6,437		5,774
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		14,317		18,257
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		15
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		15
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,246		583
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		70		53
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		332		530
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		844
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		34		81
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		16		46
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				35
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		18
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,668		33
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,668		33
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,914		601
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		70		53
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,000		548
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		844
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		34		81
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		16		46
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				35
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		18
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,668		33
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,668		33
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,914		601
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		70		53
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,000		548
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		844
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		34		81
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		16		46
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				35
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		18
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(1,668)	[1]	(18)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(1,668)	[1]	(18)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(1,668)	[1]	(18)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(1,668)	[1]	(18)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[1]	0
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]			0
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[1]	0
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,715	[3]	1,716	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3,890	[3]	5,176	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		5,191	[3]	5,191	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		$ 14,283	[3]	$ 18,176	[4]

[1] 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, 2015. At Sept. 30, 2015, derivative assets and liabilities include no obligations to return cash collateral or 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.

[2] PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities included no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[3] 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.

[4] 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.

XML

Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 16,382,625	$ 15,865,971
Less accumulated depreciation		(4,416,323)	(4,239,015)
Property, plant and equipment, net		11,966,302	11,626,956
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		11,689,760	10,927,867
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		3,341,157	3,210,242
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		823,239	827,708
Plant to be retired
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	[1]	42,336	71,534
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 486,133	$ 828,620

[1] o

XML

Borrowings and Other Financing Instruments (Tables)

9 Months Ended

Sep. 30, 2015

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At Sept. 30, 2015, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700	$	5	$	695

^(a)    This credit facility expires in October 2019.

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

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money pool borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2015		Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		4
Maximum amount outstanding	8		97
Weighted average interest rate, computed on a daily basis	N/A		0.25		%
Weighted average interest rate at period end	N/A		N/A

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for PSCo was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	700		$	700
Amount outstanding at period end	—			382
Average amount outstanding	8			167
Maximum amount outstanding	67			393
Weighted average interest rate, computed on a daily basis	0.43		%	0.31		%
Weighted average interest rate at period end	N/A			0.65

XML

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
Segment Reporting Information [Line Items]
Operating revenues	$ 1,044,704		$ 1,049,111		$ 3,132,675		$ 3,246,358
Net income (loss)	173,081		154,159		382,547		362,354
Affiliate electric revenue	2,000		2,000		6,000		8,000
Affiliate other revenue	2,000		1,000		3,000		3,000
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	884,370		881,197		2,385,519		2,377,189
Net income (loss)	167,931		139,751		330,276		289,460
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	151,562		159,837		716,774		839,469
Net income (loss)	4,548		7,235		51,784		56,230
All Other
Segment Reporting Information [Line Items]
Operating revenues	8,846		8,201		30,647		30,091
Net income (loss)	602		7,173		487		16,664
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,044,704	[1],[2]	1,049,111	[1],[2]	3,132,675	[3],[4]	3,246,358	[3],[4]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	884,305	[2]	881,102	[2]	2,385,297	[4]	2,376,935	[4]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	151,553		159,808		716,731		839,332
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	8,846	[1]	8,201	[1]	30,647	[3]	30,091	[3]
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(74)		(124)		(265)		(391)
Net income (loss)	0		0		0		0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	65		95		222		254
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	9		29		43		137
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0		$ 0		$ 0		$ 0

[1] Operating revenues include $2 million and $1 million of other affiliate revenue for the three months ended Sept. 30, 2015 and 2014, respectively.

[2] Operating revenues include $2 million of affiliate electric revenue for the three months ended Sept. 30, 2015 and 2014.

[3] Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2015 and 2014.

[4] Operating revenues include $6 million and $8 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014

XML

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - PSCo - Bonds [Member] - Series Due May 15, 2025 [Member] $ in Millions	May. 31, 2015 USD ($)
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 250
Debt Instrument, Interest Rate, Stated Percentage	2.90%

XML

Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	1 Months Ended		9 Months Ended
	Oct. 31, 2015	Apr. 30, 2012 MW	Sep. 30, 2015 USD ($)	Oct. 30, 2015 Period	Dec. 31, 2010 Kiln Group Boiler
Electric Generating Unit Mercury and Air Toxics Standards Rule
Environmental Requirements [Abstract]
Generating capacity (in MW) | MW		25
Regional Haze Rules
Environmental Requirements [Abstract]
Number of environmental groups who petitioned the U.S. Department of the Interior					2
Number of coal-fired boilers | Boiler					12
Number of coal-fired cement kilns | Kiln					1
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of phases under a consent decree which the EPA is requiring states to evaluate areas for attainment			3
Number of months in which the state would have to submit an implementation plan for the respective nonattainment areas			18 months
Number of years for the state to achieve the designated attainment standard			5 years
Capital Addition Purchase Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation | $			$ 82.4
Subsequent Event | Green House Gas Emission Standard for Existing Sources
Environmental Requirements [Abstract]
Duration for public comment (in days)	90 days
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants	50.00%
Subsequent Event | National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of hours measured for standard | Period				8
Current level of air quality concentrations (in parts per billion)				75
Proposed level of air quality concentrations (in parts per billion)				70
Maximum | Electric Generating Unit Mercury and Air Toxics Standards Rule
Environmental Requirements [Abstract]
Number of years before affected facilities must demonstrate compliance		4 years
Minimum | Electric Generating Unit Mercury and Air Toxics Standards Rule
Environmental Requirements [Abstract]
Number of years before affected facilities must demonstrate compliance		3 years

XML

Other Comprehensive Income (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period				$ (23,878)
Accumulated other comprehensive loss at end of period		$ (24,084)		(24,084)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses		186,379	$ 185,510	560,021	$ 549,935
Total, pre-tax		(276,946)	(237,132)	(610,610)	(557,716)
Tax expense		103,865	82,973	228,063	195,362
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(24,086)	(23,573)	(23,878)	(23,338)
Other comprehensive income (loss) before reclassifications		(17)	(17)	(14)	(15)
Gains reclassified from net accumulated other comprehensive loss		19	(119)	(192)	(356)
Net current period other comprehensive loss		2	(136)	(206)	(371)
Accumulated other comprehensive loss at end of period		(24,084)	(23,709)	(24,084)	(23,709)
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		24	(191)	(315)	(573)
Tax expense		(5)	72	123	217
Total, net of tax		19	(119)	(192)	(356)
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[1]	9	(184)	(353)	(546)
Gains and Losses on Cash Flow Hedges | Vehicle Fuel Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	[2]	$ 15	$ (7)	$ 38	$ (27)

[1] Included in interest charges.

[2] Included in O&M expenses

XML

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Transfers into Level 3	$ 0	$ 0	$ 0	$ 0
Transfers out of Level 3	$ 0	$ 0	$ 0	$ 0

XML

Management's Opinion

9 Months Ended

Sep. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Management's Opinion

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of Sept. 30, 2015 and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2015 and 2014; and its cash flows for the nine months endedSept. 30, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2015 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, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2014. 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, 2014, filed with the SEC on Feb. 20, 2015. 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.

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MMBTU in Thousands, $ in Millions		Sep. 30, 2015 USD ($) gal MMBTU Counterparty	Dec. 31, 2014 gal MMBTU
Commodity Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months		$ (0.1)
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		10
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		4
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 5.6
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		10.00%
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 23.9
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		42.00%
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 5.7
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		10.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months		$ (1.0)
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	9,621	735
Vehicle Fuel Commodity (in gallons)
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | gal	[1],[2]	79	127

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

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

XML

Benefit Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,065		$	5,985		$	232		$	479
Interest cost	12,714			13,319			4,375			5,926
Expected return on plan assets	(18,147		)	(17,677		)	(5,951		)	(7,554		)
Amortization of prior service credit	(784		)	(773		)	(1,562		)	(1,562		)
Amortization of net loss	9,094			8,473			618			1,609
Net periodic benefit cost (credit)	9,942			9,327			(2,288		)	(1,102		)
Cost not recognized due to the effects of regulation	(366		)	—			—			—
Net benefit cost (credit) recognized for financial reporting	$	9,576		$	9,327		$	(2,288	)	$	(1,102	)

	Nine Months Ended Sept. 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	21,195		$	17,955		$	696		$	1,436
Interest cost	38,142			39,957			13,124			17,778
Expected return on plan assets	(54,442		)	(53,031		)	(17,852		)	(22,661		)
Amortization of prior service credit	(2,352		)	(2,319		)	(4,686		)	(4,685		)
Amortization of net loss	27,282			25,419			1,856			4,826
Net periodic benefit cost (credit)	29,825			27,981			(6,862		)	(3,306		)
Cost not recognized due to the effects of regulation	(1,098		)	—			—			—
Net benefit cost (credit) recognized for financial reporting	$	28,727		$	27,981		$	(6,862	)	$	(3,306	)

XML

Segment Information (Tables)

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Results by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2015
Operating revenues (a)(b)	$	884,305	$	151,553	$	8,846	$	—		$	1,044,704
Intersegment revenues	65		9		—		(74		)	—
Total revenues	$	884,370	$	151,562	$	8,846	$	(74	)	$	1,044,704
Net income	$	167,931	$	4,548	$	602	$	—		$	173,081

(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

^(a)    Operating revenues include $2 million of affiliate electric revenue for the three months ended Sept. 30, 2015and 2014.

^(b)    Operating revenues include $2 million and $1 million of other affiliate revenue for the three months ended Sept. 30, 2015 and 2014, respectively.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2015
Operating revenues (a)(b)	$	2,385,297	$	716,731	$	30,647	$	—		$	3,132,675
Intersegment revenues	222		43		—		(265		)	—
Total revenues	$	2,385,519	$	716,774	$	30,647	$	(265	)	$	3,132,675
Net income	$	330,276	$	51,784	$	487	$	—		$	382,547

(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

^(a)    Operating revenues include $6 million and $8 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014, respectively.

^(b)    Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2015 and 2014.

XML

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)		3 Months Ended				9 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges		$ 0		$ 0		$ 0		$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions		0		0		0		0
Designated as Hedging Instrument | Cash Flow Hedges
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		(29,000)		(27,000)		(24,000)		(24,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		24,000		(191,000)		(315,000)		(573,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0		0		0		0
Pre-tax gains (losses) recognized during the period in income		0		0				0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[1]	9,000		(184,000)		(353,000)		(546,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0		0		0		0
Pre-tax gains (losses) recognized during the period in income		0		0				0
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel And Other Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		(29,000)		(27,000)		(24,000)		(24,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[2]	15,000		(7,000)		38,000		(27,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0		0		0		0
Pre-tax gains (losses) recognized during the period in income		0		0				0
Other Derivative Instruments
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(2,140,000)		(2,126,000)		(2,496,000)		5,784,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0		0		5,460,000		(8,579,000)
Pre-tax gains (losses) recognized during the period in income		(405,000)		(209,000)		(5,734,000)		(4,589,000)
Other Derivative Instruments | Commodity Trading
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss						0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities						0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss						0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)						0
Pre-tax gains (losses) recognized during the period in income	[3]					191,000
Other Derivative Instruments | Natural Gas Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(2,140,000)		(2,126,000)		(2,496,000)		5,784,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0		0		5,460,000	[4]	(8,579,000)	[4]
Pre-tax gains (losses) recognized during the period in income		(405,000)	[4]	$ (209,000)	[3]	(5,925,000)	[4]	$ (4,589,000)	[4]
Other Derivative Instruments | Natural Gas Commodity for Electric Generation [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		$ 400,000				$ 500,000

[1] Recorded to interest charges.

[2] Recorded to O&M expenses.

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

[4] Amounts for the three and nine months ended Sept. 30, 2015 included $0.4 million and $0.5 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Losses for the nine months ended Sept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months ended Sept. 30, 2015 and 2014 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.

XML

Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2015

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Loss, Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended Sept. 30, 2015			Three Months Ended Sept. 30, 2014
Accumulated other comprehensive loss at July 1	$	(24,086	)	$	(23,573	)
Other comprehensive loss before reclassifications	(17		)	(17		)
Losses (gains) reclassified from net accumulated other comprehensive loss	19			(119		)
Net current period other comprehensive income (loss)	2			(136		)
Accumulated other comprehensive loss at Sept. 30	$	(24,084	)	$	(23,709	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2015			Nine Months Ended Sept. 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)	$	(23,338	)
Other comprehensive loss before reclassifications	(14		)	(15		)
Gains reclassified from net accumulated other comprehensive loss	(192		)	(356		)
Net current period other comprehensive loss	(206		)	(371		)
Accumulated other comprehensive loss at Sept. 30	$	(24,084	)	$	(23,709	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2015				Three Months Ended Sept. 30, 2014
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	9		(a)	$	(184	)	(a)
Vehicle fuel derivatives	15			(b)	(7		)	(b)
Total, pre-tax	24				(191		)
Tax expense	(5		)		72
Total amounts reclassified, net of tax	$	19			$	(119	)

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2015				Nine Months Ended Sept. 30, 2014
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(353	)	(a)	$	(546	)	(a)
Vehicle fuel derivatives	38			(b)	(27		)	(b)
Total, pre-tax	(315		)		(573		)
Tax expense	123				217
Total amounts reclassified, net of tax	$	(192	)		$	(356	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

XML

Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$ 277,134	$ 346,007
Less allowance for bad debts	(20,563)	(23,122)
Accounts receivable, net	$ 256,571	$ 322,885

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Sep. 30, 2015	Dec. 31, 2014
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	100	100
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	100	100

XML

Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Inventories	$ 237,764	$ 238,979
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	58,532	55,491
Fuel
Public Utilities, Inventory [Line Items]
Inventories	90,135	80,963
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 89,097	$ 102,525

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 382,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 5,000	$ 6,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Operating revenues
Electric	$ 884,305	$ 881,102	$ 2,385,297	$ 2,376,935
Natural gas	151,553	159,808	716,731	839,332
Steam and other	8,846	8,201	30,647	30,091
Total operating revenues	1,044,704	1,049,111	3,132,675	3,246,358
Operating expenses
Electric fuel and purchased power	311,347	368,860	930,107	1,052,400
Cost of natural gas sold and transported	44,953	60,073	354,825	487,159
Cost of sales — steam and other	3,596	3,538	12,938	11,951
Operating and maintenance expenses	186,379	185,510	560,021	549,935
Demand side management program expenses	33,040	36,120	96,622	105,993
Depreciation and amortization	104,228	95,075	305,517	283,506
Taxes (other than income taxes)	45,987	38,862	146,895	122,467
Total operating expenses	729,530	788,038	2,406,925	2,613,411
Operating income	315,174	261,073	725,750	632,947
Other income, net	1,222	1,720	2,674	3,429
Allowance for funds used during construction — equity	3,958	12,315	10,155	36,697
Interest charges and financing costs
Interest charges — includes other financing costs of $1,611, $1,546, $4,671 and $4,798, respectively	44,875	42,540	131,859	128,941
Allowance for funds used during construction — debt	(1,467)	(4,564)	(3,890)	(13,584)
Total interest charges and financing costs	43,408	37,976	127,969	115,357
Income before income taxes	276,946	237,132	610,610	557,716
Income taxes	103,865	82,973	228,063	195,362
Net income	$ 173,081	$ 154,159	$ 382,547	$ 362,354

XML

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 0	$ 0
Collateral posted on derivative instruments	0	0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Operating activities
Net income	$ 382,547	$ 362,354
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	309,048	287,141
Demand side management program amortization	2,776	3,309
Deferred income taxes	185,212	120,585
Amortization of Investment Tax Credits	(2,200)	(2,202)
Allowance for equity funds used during construction	(10,155)	(36,697)
Net realized and unrealized hedging and derivative transactions	3,255	(6,946)
Changes in operating assets and liabilities:
Accounts receivable	61,044	55,070
Accrued unbilled revenues	92,819	58,758
Inventories	1,215	(26,409)
Prepayments and other	75,488	1,001
Accounts payable	(78,610)	(86,984)
Net regulatory assets and liabilities	43,125	110,692
Other current liabilities	(36,587)	(43,323)
Pension and other employee benefit obligations	(22,653)	(37,769)
Change in other noncurrent assets	2,273	5,353
Change in other noncurrent liabilities	(30,667)	(15,355)
Net cash provided by operating activities	977,930	748,578
Investing activities
Utility capital/construction expenditures	(668,381)	(832,270)
Allowance for equity funds used during construction	10,155	36,697
Investments in utility money pool arrangement	(150,300)	(587,000)
Repayments from utility money pool arrangement	166,300	659,000
Net cash used in investing activities	(642,226)	(723,573)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(382,000)	253,000
Borrowings under utility money pool arrangement	67,000	303,000
Repayments under utility money pool arrangement	(67,000)	(292,000)
Proceeds from issuance of long-term debt	246,826	295,601
Repayments of Long-term Debt	0	(275,000)
Proceeds from Contributions from Parent	73,718	35,486
Dividends paid to parent	(247,174)	(355,547)
Net cash used in financing activities	(308,630)	(35,460)
Net change in cash and cash equivalents	27,074	(10,455)
Cash and cash equivalents at beginning of period	7,635	21,089
Cash and cash equivalents at end of period	34,709	10,634
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(145,569)	(136,045)
Cash received (paid) for income taxes, net	38,349	(67,717)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 104,965	$ 125,498

XML

Rate Matters (Details) $ in Millions	1 Months Ended				9 Months Ended	12 Months Ended
	Jul. 31, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Feb. 28, 2015	Sep. 30, 2015 USD ($) GWh	Dec. 31, 2014 GWh
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case
Rate Matters [Abstract]
Public Utilities, Requested Equity Capital Structure, Percentage			56.00%
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 40.5
Public Utilities, Requested Rate Increase (Decrease), Percentage			3.50%
Public Utilities, Requested Return on Equity, Percentage			10.10%
Public Utilities, Requested Rate Base, Amount			$ 1,260.0
Public Utilities, Total Revenue Impact			40.4
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates	$ 0.0
Public Utilities, Decrease In Request By Corrections And Adjustments Based On Rebuttal Testimony	0.0
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony	40.5
Public Utilities, Total Revenue Impact From Rebuttal Testimony	40.4
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 7.6
Public Utilities, Requested Rate Increase (Decrease), Percentage			0.70%
Public Utilities, Requested Return on Equity, Percentage			10.10%
Public Utilities, Requested Rate Base, Amount			$ 1,310.0
Public Utilities, Total Revenue Impact			29.3
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates	7.0
Public Utilities, Decrease In Request By Corrections And Adjustments Based On Rebuttal Testimony	0.0
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony	14.6
Public Utilities, Total Revenue Impact From Rebuttal Testimony	29.3
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2017 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 18.1
Public Utilities, Requested Rate Increase (Decrease), Percentage			1.50%
Public Utilities, Requested Return on Equity, Percentage			10.30%
Public Utilities, Requested Rate Base, Amount			$ 1,360.0
Public Utilities, Total Revenue Impact			39.3
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates	6.4
Public Utilities, Decrease In Request By Corrections And Adjustments Based On Rebuttal Testimony	(7.7)
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony	16.8
Public Utilities, Total Revenue Impact From Rebuttal Testimony	38.5
Demand Side Management Cost Adjustment 2014 [Member]
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (In GWh) | GWh						384
Demand Side Management Cost Adjustment, 2015 [Member]
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (In GWh) | GWh					400
Public Utilities, Approved Electric Demand Side Management Budget	81.6
Public Utilities, Approved Gas Demand Side Management Budget	13.1
Demand Side Management Cost Adjustment [Member]
Rate Matters [Abstract]
Public Utilities, Incentive Award Upon Achieving Savings Goal					$ 5.0
Public Utilities, Percentage Of Net Economic Benefits On Which Incentive Is Earned					5.00%
Public Utilities, Maximum Annual Incentive					$ 30.0
Demand Side Management Cost Adjustment, 2016 [Member]
Rate Matters [Abstract]
Public Utilities, Approved Electric Demand Side Management Budget	78.7
Public Utilities, Approved Gas Demand Side Management Budget	13.6
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2015 [Member]
Rate Matters [Abstract]
Public Utilities, Revenue Impact Of Requested Rider			(0.1)
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony	(0.1)
Public Utilities, Revenue Projection Of Requested Rider			67.0
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016 [Member]
Rate Matters [Abstract]
Public Utilities, Revenue Impact Of Requested Rider			21.7
Public Utilities, Decrease In Request By Transfer Of Operating And Maintenance Expense To Base Rates		$ (24.1)
Public Utilities, Decrease To Return On Equity And Capital Structure		(8.2)
Public Utilities, Increase in Request By Transfer meter replacement program from base rates to rider		1.7
Public Utilities, Recommended Rider Increase (Decrease)		(8.9)
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony	14.7
Public Utilities, Revenue Projection Of Requested Rider			81.7
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017 [Member]
Rate Matters [Abstract]
Public Utilities, Revenue Impact Of Requested Rider			21.2
Public Utilities, Decrease In Request By Transfer Of Operating And Maintenance Expense To Base Rates		(2.0)
Public Utilities, Decrease To Return On Equity And Capital Structure		(3.6)
Public Utilities, Increase in Request By Transfer meter replacement program from base rates to rider		1.7
Public Utilities, Recommended Rider Increase (Decrease)		17.3
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony	$ 21.7
Public Utilities, Revenue Projection Of Requested Rider			103.4
CPUC Proceeding - Annual Electric Earnings Test
Rate Matters [Abstract]
Public Utilities, Return On Equity Threshold For Earnings Sharing For 2015 Through 2017				9.83%
Colorado Public Utilities Commission Staff (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount			40.5
Public Utilities, Decrease To Requested Return On Equity		(12.8)
Public Utilities, Decrease To Cost Of Debt And Capital Structure		(12.8)
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment		(11.2)
Public Utilities, Decrease In Request To Move To Historical Test Year		(10.5)
Public Utilities, Decrease To O&M Expenses		(3.5)
Public Utilities, Decrease Related To Other, Net		(4.4)
Public Utilities, Total Decrease Adjustment Related To Requested Rate Increase		(55.2)
Public Utilities, Recommended Rate Increase (Decrease), Amount		(14.7)
Colorado Public Utilities Commission Staff (CPUC) | Demand Side Management Cost Adjustment, 2015 through 2020 [Member]
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (In GWh) | GWh					400
Public Utilities, Annual Earnings Limit					$ 84.3
Office of Consumer Counsel [Member] | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 40.5
Public Utilities, Decrease To Requested Return On Equity		(13.7)
Public Utilities, Decrease To Cost Of Debt And Capital Structure		(4.8)
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment		4.8
Public Utilities, Decrease In Request To Move To Historical Test Year		(16.4)
Public Utilities, Decrease To O&M Expenses		(2.7)
Public Utilities, Decrease Related To Other, Net		(1.9)
Public Utilities, Total Decrease Adjustment Related To Requested Rate Increase		(34.7)
Public Utilities, Recommended Rate Increase (Decrease), Amount		$ 5.8

XML

Selected Balance Sheet Data (Tables)

9 Months Ended

Sep. 30, 2015

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	277,134		$	346,007
Less allowance for bad debts	(20,563		)	(23,122		)
	$	256,571		$	322,885

Inventories

(Thousands of Dollars)	Sept. 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	58,532	$	55,491
Fuel	90,135		80,963
Natural gas	89,097		102,525
	$	237,764	$	238,979

Property, Plant and Equipment, Net

(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	11,689,760		$	10,927,867
Natural gas plant	3,341,157			3,210,242
Common and other property	823,239			827,708
Plant to be retired (a)	42,336			71,534
Construction work in progress	486,133			828,620
Total property, plant and equipment	16,382,625			15,865,971
Less accumulated depreciation	(4,416,323		)	(4,239,015		)
	$	11,966,302		$	11,626,956

^(a)  PSCo’s Cherokee Unit 3 was retired in August 2015.  In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC).  Amounts are presented net of accumulated depreciation.

XML

Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Purchased Power Agreements [Abstract]
Generating capacity under long term purchased power agreements	1,802	1,802
Purchase Power Agreement Duration, Maximum (year)	2032	2032

XML

Rate Matters (Tables)

9 Months Ended

Sep. 30, 2015

Public Utilities, General Disclosures [Abstract]

Colorado 2015 Multi-Year Gas Rate Case - Base Rate Answer Testimony [Table Text Block]

The following table reflects the current positions of Staff and OCC:

(Millions of Dollars)	Staff			OCC
PSCo’s filed 2015 base rate request	$	40.5		$	40.5
ROE	(12.8		)	(13.7		)
Capital structure and cost of debt	(12.8		)	(4.8		)
Cherokee pipeline adjustment	(11.2		)	4.8
Move to 2014 HTY	(10.5		)	(16.4		)
Operating and maintenance (O&M) expenses	(3.5		)	(2.7		)
Other, net	(4.4		)	(1.9		)
Total adjustments	$	(55.2	)	$	(34.7	)
Recommended (decrease) increase	$	(14.7	)	$	5.8

Colorado 2015 Multi-Year Gas Rate Case [Table Text Block]

The following table summarizes the request:

(Millions of Dollars)	2015			2016 Step		2017 Step
Total base rate increase	$	40.5		$	7.6	$	18.1
Incremental PSIA rider revenues	(0.1		)	21.7		21.2
Total revenue impact	$	40.4		$	29.3	$	39.3

Colorado 2015 Multi-Year Gas Rate Case - PSIA Rider Answer Testimony [Table Text Block]

The Staff’s recommendation for the PSIA rider is as follows:

(Millions of Dollars)	2016			2017
PSCo’s filed incremental PSIA request	$	21.7		$	21.2
Transfer PSIA O&M to base rates	(24.1		)	(2.0		)
ROE and capital structure	(8.2		)	(3.6		)
Transfer meter replacement program from base rates to PSIA	1.7			1.7
Total	$	(8.9	)	$	17.3

Colorado 2015 Multi-Year Gas Rate Case - Rebuttal Testimony [Table Text Block]

PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows:

(Millions of Dollars)	2015			2016 Step		2017 Step
PSCo’s filed base rate request	$	40.5		$	7.6	$	18.1
Shift O&M expenses between PSIA and base rates	—			7.0		6.4
Rebuttal corrections and adjustments	—			—		(7.7		)
Total base rate request	$	40.5		$	14.6	$	16.8
Incremental PSIA rider revenues	(0.1		)	14.7		21.7
Total revenue impact from rebuttal	$	40.4		$	29.3	$	38.5

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 34,709	$ 7,635
Accounts receivable, net	256,571	322,885
Accounts receivable from affiliates	11,592	50,842
Investments in utility money pool arrangement	0	16,000
Accrued unbilled revenues	201,230	294,049
Inventories	237,764	238,979
Regulatory assets	88,275	120,120
Deferred income taxes	95,539	64,587
Derivative instruments	1,715	1,731
Prepaid taxes	17,354	90,365
Prepayments and other	21,502	23,979
Total current assets	966,251	1,231,172
Property, plant and equipment, net	11,966,302	11,626,956
Other assets
Regulatory assets	886,072	903,973
Derivative instruments	3,890	5,176
Other	46,864	48,506
Total other assets	936,826	957,655
Total assets	13,869,379	13,815,783
Current liabilities
Current portion of long-term debt	8,921	8,178
Short-term Debt	0	382,000
Accounts payable	325,178	425,133
Accounts payable to affiliates	33,430	46,736
Regulatory liabilities	152,901	134,459
Taxes accrued	132,251	159,470
Accrued interest	27,043	48,409
Dividends payable to parent	83,672	83,652
Derivative instruments	6,437	5,774
Other	80,419	72,002
Total current liabilities	850,252	1,365,813
Deferred credits and other liabilities
Deferred income taxes	2,658,792	2,437,641
Deferred investment tax credits	34,072	36,273
Regulatory liabilities	450,014	464,421
Asset retirement obligations	239,643	225,296
Derivative instruments	14,317	18,257
Customer advances	199,799	229,990
Pension and employee benefit obligations	179,276	202,031
Other	67,871	68,171
Total deferred credits and other liabilities	$ 3,843,784	$ 3,682,080
Commitments and contingencies
Capitalization
Long-term debt	$ 4,125,159	$ 3,882,051
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively	0	0
Additional paid in capital	3,551,986	3,522,788
Retained earnings	1,522,282	1,386,929
Accumulated other comprehensive loss	(24,084)	(23,878)
Total common stockholder’s equity	5,050,184	4,885,839
Total liabilities and equity	$ 13,869,379	$ 13,815,783

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Interest charges and financing costs
Other financing costs	$ 1,611	$ 1,546	$ 4,671	$ 4,798

XML

Fair Value of Financial Assets and Liabilities

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

At Sept. 30, 2015, accumulated other comprehensive losses related to interest rate derivatives included $1.0 million of net losses 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, as applicable.

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, 2015, 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 endedSept. 30, 2015 and 2014.

At Sept. 30, 2015, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses 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, 2015 and Dec. 31, 2014:

(Amounts in Thousands)(a)(b)	Sept. 30, 2015	Dec. 31, 2014
Million British thermal units of natural gas	9,621	735
Gallons of vehicle fuel	79	127

^(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, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 2015
	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	$	—		$	—		$	9	(a)	$	—	$	—
Vehicle fuel and other commodity	(29		)	—			15		(b)	—		—
Total	$	(29	)	$	—		$	24		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—		$	(2,140	)	$	—		$	—	$	(405	)	(d)
Total	$	—		$	(2,140	)	$	—		$	—	$	(405	)

	Nine Months Ended Sept. 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains)Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(353	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(24		)	—			38			(b)	—			—
Total	$	(24	)	$	—		$	(315	)		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—		$	191		(c)
Natural gas commodity	—			(2,496		)	—				5,460		(d)	(5,925		)	(d)
Total	$	—		$	(2,496	)	$	—			$	5,460		$	(5,734	)

	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	)

	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	)

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

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

^(d)  Amounts for the three and nine months endedSept. 30, 2015 included $0.4 million and $0.5 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Losses for the nine months endedSept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months endedSept. 30, 2015 and 2014 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, 2015 and 2014. 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, 2015, four of PSCo’s 10 most significant counterparties, comprising $5.6 million or 10 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Five of the 10 most significant counterparties, comprising $23.9 million or 42 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. Another of these significant counterparties, comprising $5.7 million or 10 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. 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, 2015 and Dec. 31, 2014, there were no derivative instruments with contract provisions that required the posting of collateral or settlement of the contracts.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 2015 and Dec. 31, 2014.

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, 2015:

	Sept. 30, 2015
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	1,668	$	—	$	1,668	$	(1,668	)	$	—
Total current derivative assets	$	—	$	1,668	$	—	$	1,668	$	(1,668	)	—
PPAs (a)												1,715
Current derivative instruments												$	1,715
Noncurrent derivative assets
PPAs (a)												$	3,890
Noncurrent derivative instruments												$	3,890
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	70	$	—	$	70	$	—		$	70
Other derivative instruments:
Natural gas commodity	—		2,000		—		2,000		(1,668		)	332
Other commodity	—		844		—		844		—			844
Total current derivative liabilities	$	—	$	2,914	$	—	$	2,914	$	(1,668	)	1,246
PPAs (a)												5,191
Current derivative instruments												$	6,437
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	16	$	—	$	16	$	—		$	16
Other derivative instruments:
Other commodity	—		18		—		18		—			18
Total noncurrent derivative liabilities	$	—	$	34	$	—	$	34	$	—		34
PPAs (a)												14,283
Noncurrent derivative instruments												$	14,317

^(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, 2015. At Sept. 30, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014:

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	33	$	—	$	33	$	(18	)	$	15
Total current derivative assets	$	—	$	33	$	—	$	33	$	(18	)	15
PPAs (a)												1,716
Current derivative instruments												$	1,731
Noncurrent derivative assets
PPAs (a)												$	5,176
Noncurrent derivative instruments												$	5,176
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	53	$	—	$	53	$	—		$	53
Other derivative instruments:
Natural gas commodity	—		548		—		548		(18		)	530
Total current derivative liabilities	$	—	$	601	$	—	$	601	$	(18	)	583
PPAs (a)												5,191
Current derivative instruments												$	5,774
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	46	$	—	$	46	$	—		$	46
Other derivative instruments:
Natural gas commodity	—		35		—		35		—			35
Total noncurrent derivative liabilities	$	—	$	81	$	—	$	81	$	—		81
PPAs (a)												18,176
Noncurrent derivative instruments												$	18,257

^(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, 2014. At Dec. 31, 2014, derivative assets and liabilities included no obligations to return cash collateral or 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 endedSept. 30, 2015 and 2014.

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, 2015 and 2014.

Fair Value of Long-Term Debt

As of Sept. 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,134,080	$	4,429,648	$	3,890,229	$	4,328,968

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, 2015 and Dec. 31, 2014, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	PUBLIC SERVICE CO OF COLORADO
Entity Central Index Key	0000081018
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

XML

Other Income, Net

9 Months Ended

Sep. 30, 2015

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Thousands of Dollars)	2015		2014		2015		2014
Interest income	$	162	$	729	$	537	$	1,375
Other nonoperating income	607		573		1,904		2,448
Insurance policy income (expense)	453		418		233		(394		)
Other income, net	$	1,222	$	1,720	$	2,674	$	3,429

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Comprehensive income:
Net income	$ 173,081	$ 154,159	$ 382,547	$ 362,354
Derivative instruments:
Net fair value decrease, net of tax of $(12), $(10), $(10), and $(9), respectively	(17)	(17)	(14)	(15)
Reclassification of losses (gains) to net income, net of tax of $5, $(72), $(123) and $(217), respectively	19	(119)	(192)	(356)
Other comprehensive income (loss)	2	(136)	(206)	(371)
Comprehensive income	$ 173,083	$ 154,023	$ 382,341	$ 361,983

XML

Selected Balance Sheet Data

9 Months Ended

Sep. 30, 2015

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	277,134		$	346,007
Less allowance for bad debts	(20,563		)	(23,122		)
	$	256,571		$	322,885

(Thousands of Dollars)	Sept. 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	58,532	$	55,491
Fuel	90,135		80,963
Natural gas	89,097		102,525
	$	237,764	$	238,979

(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	11,689,760		$	10,927,867
Natural gas plant	3,341,157			3,210,242
Common and other property	823,239			827,708
Plant to be retired (a)	42,336			71,534
Construction work in progress	486,133			828,620
Total property, plant and equipment	16,382,625			15,865,971
Less accumulated depreciation	(4,416,323		)	(4,239,015		)
	$	11,966,302		$	11,626,956

^(a)  PSCo’s Cherokee Unit 3 was retired in August 2015.  In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC).  Amounts are presented net of accumulated depreciation.

XML

Accounting Pronouncements

9 Months Ended

Sep. 30, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board (FASB) 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. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. PSCo does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, PSCo does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, PSCo does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

XML

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	Sept. 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.9	$	1.9
Unrecognized tax benefit — Temporary tax positions	13.8		10.0
Total unrecognized tax benefit	$	15.7	$	11.9

Tax Benefits Associated with NOL and Tax Credit Carryforwards

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

(Millions of Dollars)	Sept. 30, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(6.5	)	$	(3.9	)

XML

Segment Information

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Segment Information

Segment Information

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

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

• PSCo’s regulated electric utility segment generates, 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, 2015
Operating revenues (a)(b)	$	884,305	$	151,553	$	8,846	$	—		$	1,044,704
Intersegment revenues	65		9		—		(74		)	—
Total revenues	$	884,370	$	151,562	$	8,846	$	(74	)	$	1,044,704
Net income	$	167,931	$	4,548	$	602	$	—		$	173,081

(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

^(a)    Operating revenues include $2 million of affiliate electric revenue for the three months ended Sept. 30, 2015and 2014.

^(b)    Operating revenues include $2 million and $1 million of other affiliate revenue for the three months ended Sept. 30, 2015 and 2014, respectively.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2015
Operating revenues (a)(b)	$	2,385,297	$	716,731	$	30,647	$	—		$	3,132,675
Intersegment revenues	222		43		—		(265		)	—
Total revenues	$	2,385,519	$	716,774	$	30,647	$	(265	)	$	3,132,675
Net income	$	330,276	$	51,784	$	487	$	—		$	382,547

(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

^(a)    Operating revenues include $6 million and $8 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014, respectively.

^(b)    Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2015 and 2014.

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except to the extent noted below and in Note 5 above, 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, 2014 and in Notes 5 and 6 to the consolidated financial statements included in PSCo's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.

Purchased Power Agreements (PPAs)

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

PSCo had approximately 1,802 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2015 and Dec. 31, 2014, 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

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 2015, the Environmental Protection Agency (EPA) issued a final 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. PSCo is currently reviewing the final rule and cannot predict, at this time, whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. PSCo believes that compliance costs would be recoverable through regulatory mechanisms.

Federal CWA Waters of the United States Rule —In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings.

Air

Green House Gas (GHG) Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90-day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which PSCo operates. Until PSCo has reviewed the final rule and has more information about state implementation plans, PSCo cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. PSCo believes that compliance costs will be recoverable through regulatory mechanisms.

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 natural gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The NSPS does 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. The final rule was published in October 2015. PSCo does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

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 was published in October 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 standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if PSCo were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, PSCo had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. In June 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. PSCo believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread 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 (SO₂), nitrous oxide (NO_x), and particulate matter emissions under BART and set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a SIP that included the Clean Air Clean Jobs Act (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 Hayden Unit 1 and Hayden Unit 2 will be placed into service in late 2015 and late 2016, respectively, at an estimated combined cost of $82.4 million. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

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 challenged 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. In October, 2014, the Court granted the EPA’s request and vacated the current briefing schedule. In May 2015, the EPA published its final rule which re-affirmed the approval of the State of Colorado’s BART determination for Comanche Units 1 and 2. The determination found that the controls currently installed on the units for NOx are BART. In July 2015, WildEarth Guardians filed a petition for review of the EPA's May 2015 final rule. In September 2015, in response to a motion filed by WildEarth Guardians and the EPA, the 10^th Circuit issued an order dismissing the case.

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

Implementation of the National Ambient Air Quality Standard (NAAQS) for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where PSCo operates power plants.  However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant.  The Pawnee plant recently installed an SO₂ scrubber to reduce SO₂ emissions. The Colorado Department of Health and Environment made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA's final decision is expected by summer 2016. 

If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months, designed to achieve the NAAQS within five years.

Revisions to the NAAQS for Ozone— In October 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In Colorado, the Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard. If not in attainment, impacted areas would study the sources of nonattainment and make emission reduction plans to attain the new standards. These plans would be due to the EPA in 2020. In conjunction with CACJA, PSCo has or plans to shut down coal-fired plants in the Denver area, has installed NOx controls on Pawnee and Hayden Unit 1 and will finish installing NOx controls on Hayden Unit 2 in 2016. The final designation of nonattainment areas will be made in late 2017 based on air quality data years 2014-2016. PSCo cannot evaluate the impacts of this ruling in Colorado until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that, should NOx control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

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

Notwithstanding its petition for review, 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. This matter is now pending a decision by the FERC.

In addition, on Feb. 17, 2015, the U.S. Court of Appeals of the Ninth Circuit directed parties to the pending FERC proceeding to submit briefs addressing, among other issues, the petition for review filed by the City of Seattle seeking review of FERC’s order on remand. Parties are directed to address whether FERC’s order properly established the scope for the hearing that concluded in October 2013. Respondent-intervenors, including PSCo jointly with others, submitted briefs on May 8, 2015. Oral argument was held on June 16, 2015, and the matter is now pending before the Ninth Circuit.

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 PRPs. No accrual has been recorded for this matter.

XML

Income Taxes

9 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Except to the extent noted below, Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, 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. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Sept. 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $13 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. PSCo is not expected to accrue any income tax expense related to this adjustment. As of Sept. 30, 2015, the IRS had begun the appeals process; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009-2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2015, 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, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.9	$	1.9
Unrecognized tax benefit — Temporary tax positions	13.8		10.0
Total unrecognized tax benefit	$	15.7	$	11.9

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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(6.5	)	$	(3.9	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process and audit progress 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, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2015 or Dec. 31, 2014.

XML

Rate Matters

9 Months Ended

Sep. 30, 2015

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Note 5 to the consolidated financial statements included in PSCo’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — CPUC

Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million, or 3.5 percent, in 2015, with subsequent step increases of $7.6 million, or 0.7 percent, in 2016 and $18.1 million, or 1.5 percent, in 2017.

The request is based on a historic test year (HTY) ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan and an equity ratio of 56 percent. The rate case requests a return on equity (ROE) of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017.

PSCo also proposed a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and implementation of an earnings test for 2016 through 2017.

In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. The following table summarizes the request:

(Millions of Dollars)	2015			2016 Step		2017 Step
Total base rate increase	$	40.5		$	7.6	$	18.1
Incremental PSIA rider revenues	(0.1		)	21.7		21.2
Total revenue impact	$	40.4		$	29.3	$	39.3

In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC) issued their 2015 base rate recommendations. The following table reflects the current positions of Staff and OCC:

(Millions of Dollars)	Staff			OCC
PSCo’s filed 2015 base rate request	$	40.5		$	40.5
ROE	(12.8		)	(13.7		)
Capital structure and cost of debt	(12.8		)	(4.8		)
Cherokee pipeline adjustment	(11.2		)	4.8
Move to 2014 HTY	(10.5		)	(16.4		)
Operating and maintenance (O&M) expenses	(3.5		)	(2.7		)
Other, net	(4.4		)	(1.9		)
Total adjustments	$	(55.2	)	$	(34.7	)
Recommended (decrease) increase	$	(14.7	)	$	5.8

The Staff’s recommendation for the PSIA rider is as follows:

(Millions of Dollars)	2016			2017
PSCo’s filed incremental PSIA request	$	21.7		$	21.2
Transfer PSIA O&M to base rates	(24.1		)	(2.0		)
ROE and capital structure	(8.2		)	(3.6		)
Transfer meter replacement program from base rates to PSIA	1.7			1.7
Total	$	(8.9	)	$	17.3

In July 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows:

(Millions of Dollars)	2015			2016 Step		2017 Step
PSCo’s filed base rate request	$	40.5		$	7.6	$	18.1
Shift O&M expenses between PSIA and base rates	—			7.0		6.4
Rebuttal corrections and adjustments	—			—		(7.7		)
Total base rate request	$	40.5		$	14.6	$	16.8
Incremental PSIA rider revenues	(0.1		)	14.7		21.7
Total revenue impact from rebuttal	$	40.4		$	29.3	$	38.5

If PSCo’s revised request is accepted, PSIA revenue is projected to be $67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017.

Interim rates, subject to refund, were also implemented, effective Oct. 1, 2015, based on PSCo’s direct testimony. PSCo is expecting the ALJ’s Recommended Decision in November 2015. The final CPUC decision is expected no later than January 2016.

Annual Electric Earnings Test — In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test, in which PSCo shares with customers’ earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of Sept. 30, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test, based on annual forecasted information.

Electric, Purchased Gas and Resource Adjustment Clauses

Demand Side Management (DSM) and the Demand Side Management Cost Adjustment (DSMCA) — The CPUC approved higher savings goals and a lower financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2015. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Savings goals were 384 gigawatt hours (GWh) in 2014 and are 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million. For the years 2015 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual earnings limit of $84.3 million.

In July 2015, the CPUC approved PSCo’s 2015-2016 DSM plan:

• A 2015 DSM electric budget of $81.6 million;

• A 2015 DSM gas budget of $13.1 million;

• A 2016 DSM electric budget of $78.7 million; and

• A 2016 DSM gas budget of $13.6 million.

XML

Borrowings and Other Financing Instruments

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2015		Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		4
Maximum amount outstanding	8		97
Weighted average interest rate, computed on a daily basis	N/A		0.25		%
Weighted average interest rate at period end	N/A		N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	700		$	700
Amount outstanding at period end	—			382
Average amount outstanding	8			167
Maximum amount outstanding	67			393
Weighted average interest rate, computed on a daily basis	0.43		%	0.31		%
Weighted average interest rate at period end	N/A			0.65

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, 2015 and Dec. 31, 2014, there were $5 million and $6 million, respectively, of letters of credit outstanding 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, 2015, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700	$	5	$	695

^(a)    This credit facility expires in October 2019.

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at Sept. 30, 2015 and Dec. 31, 2014.

Long-Term Borrowings

In May 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025.

XML

Income Taxes (Details) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2015	Dec. 31, 2014
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions		$ 1,900,000	$ 1,900,000
Unrecognized tax benefit — Temporary tax positions		13,800,000	10,000,000
Total unrecognized tax benefit		15,700,000	11,900,000
NOL and tax credit carryforwards		(6,500,000)	(3,900,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible		1,000,000
Amounts accrued for penalties related to unrecognized tax benefits		$ 0	$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination	2010 and 2011	2012 and 2013
Year of carryback claim under examination	2009
Potential Tax Adjustments		$ 13,000,000
State Jurisdiction (Colorado)
Tax Audits [Abstract]
Earliest year subject to examination		2009

XML

Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2015 USD ($) Plan	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 7,065	$ 5,985	$ 21,195	$ 17,955
Interest cost		12,714	13,319	38,142	39,957
Expected return on plan assets		(18,147)	(17,677)	(54,442)	(53,031)
Amortization of prior service credit		(784)	(773)	(2,352)	(2,319)
Amortization of net loss		9,094	8,473	27,282	25,419
Net periodic benefit cost (credit)		9,942	9,327	29,825	27,981
Costs not recognized due to the effects of regulation		(366)	0	(1,098)	0
Net benefit cost (credit) recognized for financial reporting		9,576	9,327	28,727	27,981
Total contributions to the pension plans during the period	$ 20,000
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		232	479	696	1,436
Interest cost		4,375	5,926	13,124	17,778
Expected return on plan assets		(5,951)	(7,554)	(17,852)	(22,661)
Amortization of prior service credit		(1,562)	(1,562)	(4,686)	(4,685)
Amortization of net loss		618	1,609	1,856	4,826
Net periodic benefit cost (credit)		(2,288)	(1,102)	(6,862)	(3,306)
Costs not recognized due to the effects of regulation		0	0	0	0
Net benefit cost (credit) recognized for financial reporting		$ (2,288)	$ (1,102)	$ (6,862)	$ (3,306)
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Total contributions to the pension plans during the period	$ 90,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4

XML

Other Comprehensive Income

9 Months Ended

Sep. 30, 2015

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended Sept. 30, 2015			Three Months Ended Sept. 30, 2014
Accumulated other comprehensive loss at July 1	$	(24,086	)	$	(23,573	)
Other comprehensive loss before reclassifications	(17		)	(17		)
Losses (gains) reclassified from net accumulated other comprehensive loss	19			(119		)
Net current period other comprehensive income (loss)	2			(136		)
Accumulated other comprehensive loss at Sept. 30	$	(24,084	)	$	(23,709	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2015			Nine Months Ended Sept. 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)	$	(23,338	)
Other comprehensive loss before reclassifications	(14		)	(15		)
Gains reclassified from net accumulated other comprehensive loss	(192		)	(356		)
Net current period other comprehensive loss	(206		)	(371		)
Accumulated other comprehensive loss at Sept. 30	$	(24,084	)	$	(23,709	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2015				Three Months Ended Sept. 30, 2014
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	9		(a)	$	(184	)	(a)
Vehicle fuel derivatives	15			(b)	(7		)	(b)
Total, pre-tax	24				(191		)
Tax expense	(5		)		72
Total amounts reclassified, net of tax	$	19			$	(119	)

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2015				Nine Months Ended Sept. 30, 2014
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(353	)	(a)	$	(546	)	(a)
Vehicle fuel derivatives	38			(b)	(27		)	(b)
Total, pre-tax	(315		)		(573		)
Tax expense	123				217
Total amounts reclassified, net of tax	$	(192	)		$	(356	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

XML

Fair Value of Financial Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

The following table details the gross notional amounts of commodity forwards and options at Sept. 30, 2015 and Dec. 31, 2014:

(Amounts in Thousands)(a)(b)	Sept. 30, 2015	Dec. 31, 2014
Million British thermal units of natural gas	9,621	735
Gallons of vehicle fuel	79	127

^(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.

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

The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 2015
	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	$	—		$	—		$	9	(a)	$	—	$	—
Vehicle fuel and other commodity	(29		)	—			15		(b)	—		—
Total	$	(29	)	$	—		$	24		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—		$	(2,140	)	$	—		$	—	$	(405	)	(d)
Total	$	—		$	(2,140	)	$	—		$	—	$	(405	)

	Nine Months Ended Sept. 30, 2015
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains)Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(353	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(24		)	—			38			(b)	—			—
Total	$	(24	)	$	—		$	(315	)		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—		$	191		(c)
Natural gas commodity	—			(2,496		)	—				5,460		(d)	(5,925		)	(d)
Total	$	—		$	(2,496	)	$	—			$	5,460		$	(5,734	)

	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	)

	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	)

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

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

^(d)  Amounts for the three and nine months endedSept. 30, 2015 included $0.4 million and $0.5 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Losses for the nine months endedSept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months endedSept. 30, 2015 and 2014 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.

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

Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2015:

	Sept. 30, 2015
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	1,668	$	—	$	1,668	$	(1,668	)	$	—
Total current derivative assets	$	—	$	1,668	$	—	$	1,668	$	(1,668	)	—
PPAs (a)												1,715
Current derivative instruments												$	1,715
Noncurrent derivative assets
PPAs (a)												$	3,890
Noncurrent derivative instruments												$	3,890
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	70	$	—	$	70	$	—		$	70
Other derivative instruments:
Natural gas commodity	—		2,000		—		2,000		(1,668		)	332
Other commodity	—		844		—		844		—			844
Total current derivative liabilities	$	—	$	2,914	$	—	$	2,914	$	(1,668	)	1,246
PPAs (a)												5,191
Current derivative instruments												$	6,437
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	16	$	—	$	16	$	—		$	16
Other derivative instruments:
Other commodity	—		18		—		18		—			18
Total noncurrent derivative liabilities	$	—	$	34	$	—	$	34	$	—		34
PPAs (a)												14,283
Noncurrent derivative instruments												$	14,317

^(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, 2015. At Sept. 30, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014:

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	33	$	—	$	33	$	(18	)	$	15
Total current derivative assets	$	—	$	33	$	—	$	33	$	(18	)	15
PPAs (a)												1,716
Current derivative instruments												$	1,731
Noncurrent derivative assets
PPAs (a)												$	5,176
Noncurrent derivative instruments												$	5,176
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	53	$	—	$	53	$	—		$	53
Other derivative instruments:
Natural gas commodity	—		548		—		548		(18		)	530
Total current derivative liabilities	$	—	$	601	$	—	$	601	$	(18	)	583
PPAs (a)												5,191
Current derivative instruments												$	5,774
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	46	$	—	$	46	$	—		$	46
Other derivative instruments:
Natural gas commodity	—		35		—		35		—			35
Total noncurrent derivative liabilities	$	—	$	81	$	—	$	81	$	—		81
PPAs (a)												18,176
Noncurrent derivative instruments												$	18,257

^(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, 2014. At Dec. 31, 2014, derivative assets and liabilities included no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Carrying Amount and Fair Value of Long-term Debt

As of Sept. 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,134,080	$	4,429,648	$	3,890,229	$	4,328,968

XML

Other Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Other Income and Expenses [Abstract]
Interest income	$ 162	$ 729	$ 537	$ 1,375
Other nonoperating income	607	573	1,904	2,448
Insurance policy income (expense)	453	418	233	(394)
Other income, net	$ 1,222	$ 1,720	$ 2,674	$ 3,429

XML

Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility	Sep. 30, 2015 USD ($)
Line of Credit Facility [Line Items]
Credit Facility	$ 700,000,000	[1]
Drawn	5,000,000	[2]
Available	695,000,000
Direct advances on the credit facility outstanding	$ 0

[1] This credit facility expires in October 2019.

[2] Includes outstanding commercial paper and letters of credit.

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative instruments:
Net fair value (decrease) increase, tax	$ (12)	$ (10)	$ (10)	$ (9)
Reclassification of losses (gains) to net income, tax	$ 5	$ (72)	$ (123)	$ (217)

XML

Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

XML

Other Income, Net (Tables)

9 Months Ended

Sep. 30, 2015

Other Income and Expenses [Abstract]

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Thousands of Dollars)	2015		2014		2015		2014
Interest income	$	162	$	729	$	537	$	1,375
Other nonoperating income	607		573		1,904		2,448
Insurance policy income (expense)	453		418		233		(394		)
Other income, net	$	1,222	$	1,720	$	2,674	$	3,429

XML

Commitments and Contingencies, Legal Contingencies (Details)	3 Months Ended		9 Months Ended		13 Months Ended
	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Sep. 30, 2015 USD ($) Factor	Sep. 30, 2014 USD ($)	Jun. 30, 2001 USD ($)
Legal Contingencies [Abstract]
Sales to the City of Seattle	$ 1,044,704,000	$ 1,049,111,000	$ 3,132,675,000	$ 3,246,358,000
Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Accrual for legal contingency	0		0
PSCo | Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Minimum amount of damages claimed by plaintiff	34,000,000		34,000,000
Sales to the City of Seattle					$ 50,000,000
Estimated City of Seattle's claim for refunds not including interest	28,000,000		$ 28,000,000
Number of factors considered in assessment | Factor			2
Accrual for legal contingency	$ 0		$ 0

XML

Benefit Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,065		$	5,985		$	232		$	479
Interest cost	12,714			13,319			4,375			5,926
Expected return on plan assets	(18,147		)	(17,677		)	(5,951		)	(7,554		)
Amortization of prior service credit	(784		)	(773		)	(1,562		)	(1,562		)
Amortization of net loss	9,094			8,473			618			1,609
Net periodic benefit cost (credit)	9,942			9,327			(2,288		)	(1,102		)
Cost not recognized due to the effects of regulation	(366		)	—			—			—
Net benefit cost (credit) recognized for financial reporting	$	9,576		$	9,327		$	(2,288	)	$	(1,102	)

	Nine Months Ended Sept. 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	21,195		$	17,955		$	696		$	1,436
Interest cost	38,142			39,957			13,124			17,778
Expected return on plan assets	(54,442		)	(53,031		)	(17,852		)	(22,661		)
Amortization of prior service credit	(2,352		)	(2,319		)	(4,686		)	(4,685		)
Amortization of net loss	27,282			25,419			1,856			4,826
Net periodic benefit cost (credit)	29,825			27,981			(6,862		)	(3,306		)
Cost not recognized due to the effects of regulation	(1,098		)	—			—			—
Net benefit cost (credit) recognized for financial reporting	$	28,727		$	27,981		$	(6,862	)	$	(3,306	)

In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $20.0 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2015.