10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2016

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 May 13, 2016
Common Stock, $0.01 par value	100 shares

Public Service Company of Colorado meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

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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	21
Item 4 —	Controls and Procedures	25
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	26
Item 1A —	Risk Factors	26
Item 4 —	Mine Safety Disclosures	26
Item 5 —	Other Information	26
Item 6 —	Exhibits	26
SIGNATURES		27
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

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

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2016			2015
Operating revenues
Electric	$	717,462		$	749,461
Natural gas	328,494			373,203
Steam and other	11,885			12,786
Total operating revenues	1,057,841			1,135,450
Operating expenses
Electric fuel and purchased power	295,930			322,758
Cost of natural gas sold and transported	168,476			228,744
Cost of sales — steam and other	3,781			5,693
Operating and maintenance expenses	178,386			182,417
Demand side management program expenses	27,723			30,069
Depreciation and amortization	108,881			100,043
Taxes (other than income taxes)	51,474			50,326
Total operating expenses	834,651			920,050
Operating income	223,190			215,400
Other income, net	449			687
Allowance for funds used during construction — equity	4,318			2,806
Interest charges and financing costs
Interest charges — includes other financing costs of $1,739 and     $1,505, respectively	45,748			43,090
Allowance for funds used during construction — debt	(1,610		)	(1,098		)
Total interest charges and financing costs	44,138			41,992
Income before income taxes	183,819			176,901
Income taxes	67,945			65,935
Net income	$	115,874		$	110,966

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2016			2015
Net income	$	115,874		$	110,966
Other comprehensive income (loss)
Pension and retiree medical benefits:
Net pension and retiree medical benefits losses arising during the period,    net of tax of $135 and $0, respectively	(219		)	—
Derivative instruments:
Net fair value decrease, net of tax of $(1) and $(3), respectively	(2		)	(5		)
Reclassification of losses (gains) to net income, net of tax of $163 and $(64),    respectively	264			(105		)
Other comprehensive income (loss)	43			(110		)
Comprehensive income	$	115,917		$	110,856

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2016			2015
Operating activities
Net income	$	115,874		$	110,966
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	109,715			101,172
Demand side management program amortization	733			1,022
Deferred income taxes	64,562			37,771
Amortization of investment tax credits	(701		)	(733		)
Allowance for equity funds used during construction	(4,318		)	(2,806		)
Net realized and unrealized hedging and derivative transactions	2,782			5,086
Other	(388		)	—
Changes in operating assets and liabilities:
Accounts receivable	39,022			35,312
Accrued unbilled revenues	80,374			89,193
Inventories	40,165			43,638
Prepayments and other	76,646			89,210
Accounts payable	(32,194		)	(61,624		)
Net regulatory assets and liabilities	(27,163		)	73,340
Other current liabilities	15,458			43,420
Pension and other employee benefit obligations	(16,318		)	(20,496		)
Change in other noncurrent assets	595			903
Change in other noncurrent liabilities	(7,944		)	(3,734		)
Net cash provided by operating activities	456,900			541,640
Investing activities
Utility capital/construction expenditures	(238,635		)	(241,194		)
Allowance for equity funds used during construction	4,318			2,806
Investments in utility money pool arrangement	(314,000		)	(57,000		)
Repayments from utility money pool arrangement	221,000			73,000
Other	683			—
Net cash used in investing activities	(326,634		)	(222,388		)
Financing activities
Repayments of short-term borrowings, net	(14,000		)	(240,000		)
Borrowings under utility money pool arrangement	—			9,000
Repayments under utility money pool arrangement	—			(9,000		)
Capital contributions to parent	(31,162		)	—
Dividends paid to parent	(83,374		)	(83,794		)
Net cash used in financing activities	(128,536		)	(323,794		)
Net change in cash and cash equivalents	1,730			(4,542		)
Cash and cash equivalents at beginning of period	3,585			7,635
Cash and cash equivalents at end of period	$	5,315		$	3,093
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(65,225	)	$	(64,940	)
Cash received for income taxes, net	74,941			87,443
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	68,817		$	65,289

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	March 31, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	5,315		$	3,585
Accounts receivable, net	260,221			300,882
Accounts receivable from affiliates	6,548			4,909
Investments in utility money pool arrangement	93,000			—
Accrued unbilled revenues	195,838			276,212
Inventories	165,397			205,562
Regulatory assets	83,512			92,072
Deferred income taxes	58,713			62,662
Derivative instruments	2,216			1,945
Prepaid taxes	4,867			81,162
Prepayments and other	22,347			22,698
Total current assets	897,974			1,051,689
Property, plant and equipment, net	12,269,953			12,172,211
Other assets
Regulatory assets	900,878			906,275
Derivative instruments	3,092			3,478
Other	17,946			18,224
Total other assets	921,916			927,977
Total assets	$	14,089,843		$	14,151,877
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	7,255		$	8,103
Short-term debt	—			14,000
Accounts payable	287,755			352,701
Accounts payable to affiliates	38,030			76,643
Regulatory liabilities	111,143			152,823
Taxes accrued	211,137			166,660
Accrued interest	27,409			49,698
Dividends payable to parent	83,914			83,374
Derivative instruments	5,749			8,881
Other	72,513			78,910
Total current liabilities	844,905			991,793
Deferred credits and other liabilities
Deferred income taxes	2,781,159			2,720,860
Deferred investment tax credits	32,765			33,466
Regulatory liabilities	488,181			471,421
Asset retirement obligations	242,933			240,508
Derivative instruments	11,729			13,020
Customer advances	190,428			198,526
Pension and employee benefit obligations	184,510			200,774
Other	64,079			63,864
Total deferred credits and other liabilities	3,995,784			3,942,439
Commitments and contingencies
Capitalization
Long-term debt	4,097,000			4,097,493
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at March 31, 2016 and Dec. 31, 2015, respectively	—			—
Additional paid in capital	3,620,824			3,620,824
Retained earnings	1,555,123			1,523,164
Accumulated other comprehensive loss	(23,793		)	(23,836		)
Total common stockholder’s equity	5,152,154			5,120,152
Total liabilities and equity	$	14,089,843		$	14,151,877

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of March 31, 2016 and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2016 and 2015; and its cash flows for the three months endedMarch 31, 2016 and 2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2016 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, 2015 balance sheet information has been derived from the audited 2015 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2015. 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, 2015, filed with the SEC on Feb. 22, 2016. 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, 2015, 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. 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.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, PSCo does not expect the implementation of ASU 2015-17 to have a material impact on its consolidated financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. PSCo is currently evaluating the impact of adopting ASU 2016-02 on its consolidated financial statements.

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Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. PSCo is currently evaluating the impact of adopting ASU 2016-09 on its consolidated financial statements.

Recently Adopted

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. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant 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 requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. PSCo implemented the new guidance as required on Jan. 1, 2016, and as a result, $26.0 million of deferred debt issuance costs are presented as a deduction from the carrying amount of long-term debt on the consolidated balance sheet as of March 31, 2016, and $26.6 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

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 eliminates the requirement to categorize fair value measurements using a net asset value (NAV) methodology in the fair value hierarchy. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	279,677		$	321,004
Less allowance for bad debts	(19,456		)	(20,122		)
	$	260,221		$	300,882

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	58,766	$	58,128
Fuel	71,506		78,586
Natural gas	35,125		68,848
	$	165,397	$	205,562

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	11,888,887		$	11,856,126
Natural gas plant	3,490,099			3,420,249
Common and other property	863,165			862,840
Plant to be retired (a)	34,607			38,249
Construction work in progress	452,786			408,963
Total property, plant and equipment	16,729,544			16,586,427
Less accumulated depreciation	(4,459,591		)	(4,414,216		)
	$	12,269,953		$	12,172,211

^(a)  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.

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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, 2015 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 March 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. PSCo is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals); however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 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 March 31, 2016, 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 March 31, 2016, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

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

(Millions of Dollars)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.6	$	2.4
Unrecognized tax benefit — Temporary tax positions	15.0		15.0
Total unrecognized tax benefit	$	17.6	$	17.4

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

(Millions of Dollars)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(4.6	)	$	(4.3	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress and state audits resume. As the IRS Appeals and audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $11 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2016 or Dec. 31, 2015.

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, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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Pending Regulatory Proceedings — CPUC

Annual Electric Earnings Tests — As part of an annual earnings test, PSCo must share with customers’ earnings that exceed the authorized return on equity (ROE) threshold of 9.83 percent for 2015 through 2017. In April 2016, PSCo filed the 2015 earnings test, proposing an electric customer refund obligation of $14.9 million, subject to review by the CPUC. The proposed refund obligation related to the 2015 earnings test was accrued for as of March 31, 2016. The current estimate of the 2016 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of March 31, 2016.

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, 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 March 31, 2016 and Dec. 31, 2015, 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

Air

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 United States Environmental Protection Agency (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 facilities included within 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 were placed into service in November 2015 and Hayden Unit 2 is expected to be placed into service in late 2016, at an estimated combined cost of $75.2 million, completing the pollution control equipment required on PSCo plants under the CACJA. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

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 Clean Air Act (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. In February 2016, the EPA notified the Colorado Department of Health and Environment of its preliminary SO₂ designations. The EPA has proposed to designate the area near the Pawnee plant as “unclassifiable.” If finalized as proposed, the unclassifiable areas will be monitored for three years and final designations will be made by December 2020. The EPA’s final decision is expected by July 2016.

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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, which would be due in 18 months, designed to achieve the NAAQS within five years. The areas near the Comanche and Hayden power plants will be evaluated in the next designation phase, ending December 2017. PSCo’s Comanche and Hayden plants already utilize scrubbers to control SO₂ emissions. PSCo cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that, should SO₂ control system costs 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 — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In May 2015, in the remand proceeding, the FERC issued an order rejecting the City’s claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In June 2015, the City requested the FERC grant rehearing of its order, which the FERC denied in December. The City subsequently appealed this decision to the Ninth Circuit on Feb. 22, 2016.

Also in December 2015, the Ninth Circuit issued an order and held that the standard of review applied by the FERC to the contracts which the City was challenging is appropriate. The Ninth Circuit dismissed questions concerning whether the FERC properly established the scope of the hearing, and determined that the challenged orders are preliminary and that the Ninth Circuit lacks jurisdiction to review evidentiary decisions until after the FERC’s proceedings are final. The City joined the State of California in its request seeking rehearing of this order.

Preliminary calculations of the City’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 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 scope of the proceeding established by FERC is being challenged in 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 were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter.

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Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. On May 9, 2016, the district court granted PSCo’s motion to dismiss the lawsuit, essentially concluding that jurisdiction over this dispute resides with the CPUC. It is uncertain whether plaintiffs will appeal this decision. PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms as the line extension payments from developers, for which DRC is seeking a refund, have served to reduce rate base over the period in dispute. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

7. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2016		Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		1
Maximum amount outstanding	—		34
Weighted average interest rate, computed on a daily basis	N/A		0.41		%
Weighted average interest rate at period end	N/A		N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	700		$	700
Amount outstanding at period end	—			14
Average amount outstanding	25			95
Maximum amount outstanding	154			449
Weighted average interest rate, computed on a daily basis	0.69		%	0.51		%
Weighted average interest rate at period end	N/A			0.60

Letters of Credit— PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2016 and Dec. 31, 2015, there were $4 million 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 March 31, 2016, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700	$	4	$	696

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

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

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All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at March 31, 2016 and Dec. 31, 2015.

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 prices.

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 March 31, 2016, 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.

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At March 31, 2016, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months endedMarch 31, 2016 and 2015.

At March 31, 2016, 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 March 31, 2016 and Dec. 31, 2015:

(Amounts in Thousands)(a)(b)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	3,103	684
Million British thermal units of natural gas	28,140	12,515
Gallons of vehicle fuel	48	63

^(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 months ended March 31, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2016
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	402	(a)	$	—		$	—
Vehicle fuel and other commodity	(3		)	—			25		(b)	—			—
Total	$	(3	)	$	—		$	427		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	17		(c)
Natural gas commodity	—			(1,949		)	—			7,736		(d)	(3,261		)	(d)
Total	$	—		$	(1,949	)	$	—		$	7,736		$	(3,244	)

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	Three Months Ended March 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(180	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(8		)	—			11			(b)	—				—
Total	$	(8	)	$	—		$	(169	)		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—			$	189	(c)
Natural gas commodity	—			(174		)	—				(5,605		)	(d)	5,460		(d)
Total	$	—		$	(174	)	$	—			$	(5,605	)		$	5,649

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

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

^(d)  Amounts for the three months endedMarch 31, 2016 and 2015 included an immaterial amount 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. The remaining derivative settlement gains and losses for the three months endedMarch 31, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the three months ended March 31, 2016 and 2015. 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 March 31, 2016, three of PSCo’s 10 most significant counterparties, comprising $1.1 million or 1 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Six of the 10 most significant counterparties, comprising $32.7 million or 35 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 $8.5 million or 9 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Nine 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 March 31, 2016 and Dec. 31, 2015, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of PSCo were downgraded below investment grade.

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Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2016 and Dec. 31, 2015.

Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at March 31, 2016:

	March 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	891	$	2,643	$	—	$	3,534	$	(3,034	)	$	500
Total current derivative assets	$	891	$	2,643	$	—	$	3,534	$	(3,034	)	500
PPAs (a)												1,716
Current derivative instruments												$	2,216
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	50	$	—	$	50	$	—		$	50
Natural gas commodity	—		9		—		9		—			9
Total noncurrent derivative assets	$	—	$	59	$	—	$	59	$	—		59
PPAs (a)												$	3,033
Noncurrent derivative instruments												$	3,092
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	68	$	—	$	68	$	—		$	68
Other derivative instruments:
Commodity trading	1,159		2,270		—		3,429		(3,140		)	289
Natural gas commodity	—		119		—		119		—			119
Other commodity	—		92		—		92		—			92
Total current derivative liabilities	$	1,159	$	2,549	$	—	$	3,708	$	(3,140	)	568
PPAs (a)												5,181
Current derivative instruments												$	5,749
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	25	$	—	$	25	$	—		$	25
Natural gas commodity	—		6		—		6		—			6
Total noncurrent derivative liabilities	$	—	$	31	$	—	$	31	$	—		31
PPAs (a)												11,698
Noncurrent derivative instruments												$	11,729

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2016. At March 31, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $0.1 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015:

	Dec. 31, 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:
Commodity trading	$	137	$	351	$	—	$	488	$	(324	)	$	164
Natural gas commodity	—		352		—		352		(286		)	66
Total current derivative assets	$	137	$	703	$	—	$	840	$	(610	)	230
PPAs (a)												1,715
Current derivative instruments												$	1,945
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	16	$	—	$	16	$	—		$	16
Total noncurrent derivative assets	$	—	$	16	$	—	$	16	$	—		16
PPAs (a)												$	3,462
Noncurrent derivative instruments												$	3,478
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	92	$	—	$	92	$	—		$	92
Other derivative instruments:
Commodity trading	34		325		—		359		(324		)	35
Natural gas commodity	—		3,850		—		3,850		(286		)	3,564
Total current derivative liabilities	$	34	$	4,267	$	—	$	4,301	$	(610	)	3,691
PPAs (a)												5,190
Current derivative instruments												$	8,881
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	33	$	—	$	33	$	—		$	33
Total noncurrent derivative liabilities	$	—	$	33	$	—	$	33	$	—		33
PPAs (a)												12,987
Noncurrent derivative instruments												$	13,020

^(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, 2015. At Dec. 31, 2015, 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 months endedMarch 31, 2016 and 2015.

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three months ended March 31, 2016 and 2015.

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Fair Value of Long-Term Debt

As of March 31, 2016 and Dec. 31, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,104,255	$	4,552,330	$	4,105,596	$	4,376,875

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of March 31, 2016 and Dec. 31, 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

9. Other Income, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	141		$	233
Other nonoperating income	333			777
Insurance policy expense	(25		)	(323		)
Other income, net	$	449		$	687

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.

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2016
Operating revenues (a)(b)	$	717,462	$	328,494	$	11,885	$	—		$	1,057,841
Intersegment revenues	81		45		—		(126		)	—
Total revenues	$	717,543	$	328,539	$	11,885	$	(126	)	$	1,057,841
Net income	$	72,536	$	40,890	$	2,448	$	—		$	115,874

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2015
Operating revenues (a)(b)	$	749,461	$	373,203	$	12,786		$	—		$	1,135,450
Intersegment revenues	88		41		—			(129		)	—
Total revenues	$	749,549	$	373,244	$	12,786		$	(129	)	$	1,135,450
Net income (loss)	$	74,669	$	36,623	$	(326	)	$	—		$	110,966

^(a)    Operating revenues include $2 million of affiliate electric revenue for the three months ended March 31, 2016 and 2015.

^(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended March 31, 2016 and 2015.

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,466		$	7,065		$	192		$	232
Interest cost	13,849			12,714			4,518			4,375
Expected return on plan assets	(17,692		)	(18,148		)	(5,575		)	(5,951		)
Amortization of prior service credit	(807		)	(784		)	(1,562		)	(1,562		)
Amortization of net loss	6,693			9,094			483			619
Net periodic benefit cost (credit)	8,509			9,941			(1,944		)	(2,287		)
Credits (costs) not recognized due to the effects of regulation	766			(366		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	9,275		$	9,575		$	(1,944	)	$	(2,287	)

In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans, of which $16.8 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2016.

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12. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(23,836	)	$	—		$	(23,836	)
Other comprehensive loss before reclassifications	(2		)	(219		)	(221		)
Losses reclassified from net accumulated other comprehensive loss	264			—			264
Net current period other comprehensive income (loss)	262			(219		)	43
Accumulated other comprehensive loss at March 31	$	(23,574	)	$	(219	)	$	(23,793	)

	Three Months Ended March 31, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)
Other comprehensive loss before reclassifications	(5		)
Gains reclassified from net accumulated other comprehensive loss	(105		)
Net current period other comprehensive loss	(110		)
Accumulated other comprehensive loss at March 31	$	(23,988	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	402		(a)	$	(180	)	(a)
Vehicle fuel derivatives	25			(b)	11			(b)
Total, pre-tax	427				(169		)
Tax (benefit) expense	(163		)		64
Total amounts reclassified, net of tax	$	264			$	(105	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

20

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, 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 $115.9 million for the first quarter of 2016, compared with approximately $111.0 million for the same period in 2015. Net income was positively impacted by higher natural gas margins, primarily due to natural gas rate increases, as well as lower operating and maintenance (O&M) expenses, partially offset by higher depreciation.

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:

	Three Months Ended March 31
(Millions of Dollars)	2016			2015
Electric revenues	$	717		$	749
Electric fuel and purchased power	(296		)	(323		)
Electric margin	$	421		$	426

21

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

Electric Revenues

(Millions of Dollars)	2016 vs. 2015
Fuel and purchased power cost recovery	$	(24	)
Demand side management (DSM) program revenues (offset by expenses)	(4		)
Retail rate decrease	(2		)
Other, net	(2		)
Total decrease in electric revenues	$	(32	)

Electric Margin

(Millions of Dollars)	2016 vs. 2015
DSM program revenues (offset by expenses)	(4	)
Retail rate decrease	(2	)
Other, net	1
Total decrease in electric margin	(5	)

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:

	Three Months Ended March 31
(Millions of Dollars)	2016			2015
Natural gas revenues	$	328		$	373
Cost of natural gas sold and transported	(168		)	(229		)
Natural gas margin	$	160		$	144

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

Natural Gas Revenues

(Millions of Dollars)	2016 vs. 2015
Purchased natural gas adjustment clause recovery	$	(61	)
Retail rate increase	13
Other, net	3
Total decrease in natural gas revenues	$	(45	)

Natural Gas Margin

(Millions of Dollars)	2016 vs. 2015
Retail rate increase	13
Other, net	3
Total increase in natural gas margin	$	16

22

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses decreased $4.0 million, or 2.3 percent, for the first quarter of 2016. The decrease was mainly due to the timing of planned maintenance and overhauls along with lower employee benefit costs, which were partially offset by higher gas survey and damage prevention costs.

DSM Program Expenses— DSM program expenses decreased $2.3 million, or 7.8 percent, for the first quarter of 2016. The decrease was primarily attributable to lower electric recovery rates.

Depreciation and Amortization— Depreciation and amortization expense increased $8.8 million, or 8.8 percent, for the first quarter of 2016. The increase is primarily attributable to capital investments.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased $1.1 million, or 2.3 percent, for the first quarter of 2016. The increase is primarily due to higher property taxes.

AFUDC— AFUDC increased $2.0 million for the first quarter of 2016. The increase was primarily due to an increase in construction projects.

Interest Charges— Interest charges increased by $2.7 million, or 6.2 percent, for the first quarter of 2016. The increase is primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased $2.0 million for the first quarter of 2016. The increase in income tax expense was primarily due to higher pretax earnings in 2016. The ETR was 37.0 percent for the first quarter of 2016 compared with 37.3 percent for the same period in 2015.

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, 2015, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

Brush, Colo. to Castle Pines, Colo. 345 Kilovolt (KV) Transmission Line - In April 2015, the CPUC granted a certificate of public convenience and necessity to construct a new 345 KV transmission line originating from Pawnee generating station, near Brush, Colo. and terminating at the Daniels Park substation, near Castle Pines, Colo. to be placed in service by 2022.  The estimated project cost is $178 million.  The CPUC’s decision requires that project construction begin no earlier than May 2020. On April 29, 2016, PSCo filed a petition with the CPUC to request that construction be allowed to begin in 2017 for the project to be placed in service by 2019.

Boulder, Colo. Municipalization — 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 City of Boulder (Boulder) City Council passed an ordinance to establish an electric utility.

In 2013, the CPUC ruled that Boulder may not be the retail service provider to any PSCo customers located outside Boulder city limits unless Boulder can establish that PSCo is unwilling or unable to serve those customers. The CPUC also ruled that it has jurisdiction over the transfer of any facilities to Boulder that currently serve any customers located outside Boulder city limits and will determine separation matters. The CPUC has declared that Boulder must receive CPUC transfer approval prior to any eminent domain actions. Boulder appealed this ruling to the Boulder District Court and in January 2015, the Boulder District Court affirmed the CPUC decision. The Boulder District Court also dismissed a condemnation action that Boulder had filed. The CPUC must complete the separation plan proceeding, outlined below, before Boulder may refile a condemnation proceeding.

In July 2015, Boulder filed an application with the CPUC requesting approval of its proposed separation plan. In August 2015, PSCo filed a motion to dismiss Boulder’s separation proposal, arguing Boulder’s request was not permissible under Colorado law. In December 2015, the CPUC granted the motion to dismiss the application in part, holding that Boulder had no right to acquire PSCo facilities used exclusively to serve customers located outside Boulder city limits. Other portions of Boulder’s application were not dismissed, but are stayed until Boulder supplements its application at which time the CPUC will determine whether the application is complete and a proceeding can continue. The CPUC ordered a discovery process to allow Boulder to obtain technical information regarding the electric system and propose a new separation plan. Boulder is expected to refile its plan later this year. PSCo is also challenging Boulder’s 2014 formation of its utility in a case that is now before the Colorado Court of Appeals.

23

Wind Ownership Proposal — Colorado legislation allows for utilities to own up to 50 percent of new renewable resources without a competitive bidding process if the project can be developed at a reasonable price and demonstrate economic benefit.  In April 2016, the CPUC determined that the amount of renewable resources PSCo is eligible to develop under the state legislation is based on renewable resources added to the PSCo system since March 2007.

As a result, in May 2016, PSCo expects to submit a proposal to build, own and operate a 600 MW wind facility at a cost of approximately $1 billion, including transmission investment. PSCo believes its proposed facility can be constructed at a reasonable cost compared to the cost of similar renewable resources available on the market, and that it will be able to demonstrate to the CPUC and the independent evaluator that the proposed wind project meets the reasonable price standard. PSCo plans to request approval of its application by November 2016, in order to commence the project timely and capture the full production tax credit benefit for customers. If approved by the CPUC, the new facility is projected to go into service in December 2018.

Natural Gas Reserves Investments — In January 2016, PSCo filed a request with the CPUC for approval of a long-term natural gas procurement and price hedging framework.  Under the proposal a wholly-owned subsidiary of PSCo, PSCo Gas Reserves Company (PGRCo), will be formed to partner with Wexpro Development Company (Wexpro), a subsidiary of Questar Corporation, to acquire, develop and operate natural gas producing properties on a 50/50 joint basis, with production recovered under cost of service pricing through PSCo’s Gas Cost Adjustment.  If approved, PGRCo could potentially invest up to $500 million in natural gas properties over 10 years.

The requested cost of service pricing formula for PGRCo would include all costs of property acquisition and development.  The ROE would be based on PSCo’s allowed ROE, adjusted up or down a maximum of 100 basis points, based on the price of gas produced relative to market prices.

If the CPUC approves the framework, PSCo and Wexpro will seek to identify and acquire specific natural gas producing properties that would be beneficial to PSCo’s gas customers and seek CPUC approval of these specific investments.

Key dates in the procedural schedule are as follows:

• Supplemental direct testimony — June 27, 2016;

• Intervenor testimony — Aug. 26, 2016;

• Rebuttal testimony — Oct. 25, 2016;

• Hearings — Dec. 5-9, 2016;

• Statement of position — Jan. 6, 2017; and

• A CPUC decision is anticipated in 2017.

Joint Dispatch Agreement (JDA) — In February 2016, the FERC approved a JDA between PSCo, Black Hills Colorado Electric Utility Company, LP and Platte River Power Authority. Through the JDA, energy is dispatched to economically serve the combined electric customer loads of the three systems. In circumstances where PSCo is the lowest cost producer, it will sell its excess generation to other JDA counterparties. Margins on these sales would be shared among PSCo and its customers, of which 10 percent would be retained by PSCo. The JDA parties estimate the combined net benefits of the agreement would be approximately $4.5 million, annually. The agreement results in a reduction in total energy costs for the parties, of which approximately $1.4 million would be allocated to PSCo’s customers. As part of the agreement, PSCo will earn a management fee to administer the JDA. Operations under the JDA are expected to begin in the summer of 2016.

24

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, 2015. 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 or 2017.

Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) - In 2015, PSCo filed changes to its transmission formula rate and production formula rate to modify the treatment of ADIT to comply with 2015 IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings are intended to ensure that PSCo is in compliance with IRS rules and may continue to use accelerated tax depreciation. In December 2015, the FERC required PSCo to submit additional information regarding its formula rate changes. In April 2016, FERC accepted the PSCo formula rate changes, subject to a compliance filing.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of March 31, 2016, 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

Effective January 2016, PSCo implemented the general ledger modules of a new enterprise resource planning (ERP) system to improve certain financial and related transaction processes. During 2016 and 2017, PSCo will continue implementing additional modules and expects to begin conversion of existing work management systems to this new ERP system. In connection with this ongoing implementation, PSCo has updated and will continue updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting procedures. PSCo does not believe the implementation of the general ledger modules, which occurred during the period ended March 31, 2016, materially affected its internal control over financial reporting. PSCo also does not expect the implementation of the additional modules to materially affect its internal control over financial reporting.

No other changes in PSCo’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, PSCo’s internal control over financial reporting.

25

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 a 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, 2015, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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 March 31, 2016 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.

26

SIGNATURES

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

		Public Service Company of Colorado
May 13, 2016	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

27

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: May 13, 2016

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Robert C. Frenzel, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 13, 2016

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

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 March 31, 2016, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of PSCo certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

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

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

Date: May 13, 2016

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

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, 2015, 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.

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Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 13, 2016
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	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating revenues
Electric	$ 717,462	$ 749,461
Natural gas	328,494	373,203
Steam and other	11,885	12,786
Total operating revenues	1,057,841	1,135,450
Operating expenses
Electric fuel and purchased power	295,930	322,758
Cost of natural gas sold and transported	168,476	228,744
Cost of sales — steam and other	3,781	5,693
Operating and maintenance expenses	178,386	182,417
Demand side management program expenses	27,723	30,069
Depreciation and amortization	108,881	100,043
Taxes (other than income taxes)	51,474	50,326
Total operating expenses	834,651	920,050
Operating income	223,190	215,400
Other income, net	449	687
Allowance for funds used during construction — equity	4,318	2,806
Interest charges and financing costs
Interest charges — includes other financing costs of $1,739 and $1,505, respectively	45,748	43,090
Allowance for funds used during construction — debt	(1,610)	(1,098)
Total interest charges and financing costs	44,138	41,992
Income before income taxes	183,819	176,901
Income taxes	67,945	65,935
Net income	$ 115,874	$ 110,966

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Interest charges and financing costs
Other financing costs	$ 1,739	$ 1,505

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Comprehensive income:
Net income	$ 115,874	$ 110,966
Net pension and retiree medical benefits losses arising during the period, net of tax of $135 and $0, respectively	(219)	0
Derivative instruments:
Net fair value decrease, net of tax of $(1) and $(3), respectively	(2)	(5)
Reclassification of losses (gains) to net income, net of tax of $163 and $(64), respectively	264	(105)
Other comprehensive income (loss)	43	(110)
Comprehensive income	$ 115,917	$ 110,856

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative instruments:
Net fair value (decrease) increase, tax	$ (1)	$ (3)
Reclassification of losses (gains) to net income, tax	163	(64)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	$ 135	$ 0

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating activities
Net income	$ 115,874	$ 110,966
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	109,715	101,172
Demand side management program amortization	733	1,022
Deferred income taxes	64,562	37,771
Amortization of Investment Tax Credits	(701)	(733)
Allowance for equity funds used during construction	(4,318)	(2,806)
Net realized and unrealized hedging and derivative transactions	2,782	5,086
Other Operating Activities, Cash Flow Statement	(388)	0
Changes in operating assets and liabilities:
Accounts receivable	39,022	35,312
Accrued unbilled revenues	80,374	89,193
Inventories	40,165	43,638
Prepayments and other	76,646	89,210
Accounts payable	(32,194)	(61,624)
Net regulatory assets and liabilities	(27,163)	73,340
Other current liabilities	15,458	43,420
Pension and other employee benefit obligations	(16,318)	(20,496)
Change in other noncurrent assets	595	903
Change in other noncurrent liabilities	(7,944)	(3,734)
Net cash provided by operating activities	456,900	541,640
Investing activities
Utility capital/construction expenditures	(238,635)	(241,194)
Allowance for equity funds used during construction	4,318	2,806
Investments in utility money pool arrangement	(314,000)	(57,000)
Repayments from utility money pool arrangement	221,000	73,000
Payments for (Proceeds from) Other Investing Activities	683	0
Net cash used in investing activities	(326,634)	(222,388)
Financing activities
Repayments of short-term borrowings, net	(14,000)	(240,000)
Borrowings under utility money pool arrangement	0	9,000
Repayments under utility money pool arrangement	0	(9,000)
Proceeds from Contributions from Parent	(31,162)	0
Dividends paid to parent	(83,374)	(83,794)
Net cash used in financing activities	(128,536)	(323,794)
Net change in cash and cash equivalents	1,730	(4,542)
Cash and cash equivalents at beginning of period	3,585	7,635
Cash and cash equivalents at end of period	5,315	3,093
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(65,225)	(64,940)
Cash received for income taxes, net	74,941	87,443
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 68,817	$ 65,289

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 5,315	$ 3,585
Accounts receivable, net	260,221	300,882
Accounts receivable from affiliates	6,548	4,909
Investments in utility money pool arrangement	93,000	0
Accrued unbilled revenues	195,838	276,212
Inventories	165,397	205,562
Regulatory assets	83,512	92,072
Deferred income taxes	58,713	62,662
Derivative instruments	2,216	1,945
Prepaid taxes	4,867	81,162
Prepayments and other	22,347	22,698
Total current assets	897,974	1,051,689
Property, plant and equipment, net	12,269,953	12,172,211
Other assets
Regulatory assets	900,878	906,275
Derivative instruments	3,092	3,478
Other	17,946	18,224
Total other assets	921,916	927,977
Total assets	14,089,843	14,151,877
Current liabilities
Current portion of long-term debt	7,255	8,103
Short-term Debt	0	14,000
Accounts payable	287,755	352,701
Accounts payable to affiliates	38,030	76,643
Regulatory liabilities	111,143	152,823
Taxes accrued	211,137	166,660
Accrued interest	27,409	49,698
Dividends payable to parent	83,914	83,374
Derivative instruments	5,749	8,881
Other	72,513	78,910
Total current liabilities	844,905	991,793
Deferred Tax Liabilities, Net, Noncurrent	2,781,159	2,720,860
Deferred credits and other liabilities
Deferred investment tax credits	32,765	33,466
Regulatory liabilities	488,181	471,421
Asset retirement obligations	242,933	240,508
Derivative instruments	11,729	13,020
Customer advances	190,428	198,526
Pension and employee benefit obligations	184,510	200,774
Other	64,079	63,864
Total deferred credits and other liabilities	$ 3,995,784	$ 3,942,439
Commitments and contingencies
Capitalization
Long-term debt	$ 4,097,000	$ 4,097,493
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at March 31, 2016 and Dec. 31, 2015, respectively	0	0
Additional paid in capital	3,620,824	3,620,824
Retained earnings	1,555,123	1,523,164
Accumulated other comprehensive loss	(23,793)	(23,836)
Total common stockholder’s equity	5,152,154	5,120,152
Total liabilities and equity	$ 14,089,843	$ 14,151,877

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	100	100
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	100	100

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Management's Opinion

3 Months Ended

Mar. 31, 2016

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 March 31, 2016 and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2016 and 2015; and its cash flows for the three months endedMarch 31, 2016 and 2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2016 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, 2015 balance sheet information has been derived from the audited 2015 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2015. 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, 2015, filed with the SEC on Feb. 22, 2016. Due to the seasonality of PSCo’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2016

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, 2015, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Accounting Pronouncements

3 Months Ended

Mar. 31, 2016

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. 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.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, PSCo does not expect the implementation of ASU 2015-17 to have a material impact on its consolidated financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. PSCo is currently evaluating the impact of adopting ASU 2016-02 on its consolidated financial statements.

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. PSCo is currently evaluating the impact of adopting ASU 2016-09 on its consolidated financial statements.

Recently Adopted

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. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant 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 requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. PSCo implemented the new guidance as required on Jan. 1, 2016, and as a result, $26.0 million of deferred debt issuance costs are presented as a deduction from the carrying amount of long-term debt on the consolidated balance sheet as of March 31, 2016, and $26.6 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

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 eliminates the requirement to categorize fair value measurements using a net asset value (NAV) methodology in the fair value hierarchy. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements.

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Selected Balance Sheet Data

3 Months Ended

Mar. 31, 2016

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	279,677		$	321,004
Less allowance for bad debts	(19,456		)	(20,122		)
	$	260,221		$	300,882

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	58,766	$	58,128
Fuel	71,506		78,586
Natural gas	35,125		68,848
	$	165,397	$	205,562

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	11,888,887		$	11,856,126
Natural gas plant	3,490,099			3,420,249
Common and other property	863,165			862,840
Plant to be retired (a)	34,607			38,249
Construction work in progress	452,786			408,963
Total property, plant and equipment	16,729,544			16,586,427
Less accumulated depreciation	(4,459,591		)	(4,414,216		)
	$	12,269,953		$	12,172,211

^(a)  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.

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Income Taxes

3 Months Ended

Mar. 31, 2016

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, 2015 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 March 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. PSCo is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals); however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 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 March 31, 2016, 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 March 31, 2016, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

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

(Millions of Dollars)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.6	$	2.4
Unrecognized tax benefit — Temporary tax positions	15.0		15.0
Total unrecognized tax benefit	$	17.6	$	17.4

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

(Millions of Dollars)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(4.6	)	$	(4.3	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress and state audits resume. As the IRS Appeals and audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $11 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2016 or Dec. 31, 2015.

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Rate Matters

3 Months Ended

Mar. 31, 2016

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, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — CPUC

Annual Electric Earnings Tests — As part of an annual earnings test, PSCo must share with customers’ earnings that exceed the authorized return on equity (ROE) threshold of 9.83 percent for 2015 through 2017. In April 2016, PSCo filed the 2015 earnings test, proposing an electric customer refund obligation of $14.9 million, subject to review by the CPUC. The proposed refund obligation related to the 2015 earnings test was accrued for as of March 31, 2016. The current estimate of the 2016 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of March 31, 2016.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2016

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, 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 March 31, 2016 and Dec. 31, 2015, 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

Air

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 United States Environmental Protection Agency (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 facilities included within 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 were placed into service in November 2015 and Hayden Unit 2 is expected to be placed into service in late 2016, at an estimated combined cost of $75.2 million, completing the pollution control equipment required on PSCo plants under the CACJA. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

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 Clean Air Act (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. In February 2016, the EPA notified the Colorado Department of Health and Environment of its preliminary SO₂ designations. The EPA has proposed to designate the area near the Pawnee plant as “unclassifiable.” If finalized as proposed, the unclassifiable areas will be monitored for three years and final designations will be made by December 2020. The EPA’s final decision is expected by July 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, which would be due in 18 months, designed to achieve the NAAQS within five years. The areas near the Comanche and Hayden power plants will be evaluated in the next designation phase, ending December 2017. PSCo’s Comanche and Hayden plants already utilize scrubbers to control SO₂ emissions. PSCo cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that, should SO₂ control system costs 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 — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In May 2015, in the remand proceeding, the FERC issued an order rejecting the City’s claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In June 2015, the City requested the FERC grant rehearing of its order, which the FERC denied in December. The City subsequently appealed this decision to the Ninth Circuit on Feb. 22, 2016.

Also in December 2015, the Ninth Circuit issued an order and held that the standard of review applied by the FERC to the contracts which the City was challenging is appropriate. The Ninth Circuit dismissed questions concerning whether the FERC properly established the scope of the hearing, and determined that the challenged orders are preliminary and that the Ninth Circuit lacks jurisdiction to review evidentiary decisions until after the FERC’s proceedings are final. The City joined the State of California in its request seeking rehearing of this order.

Preliminary calculations of the City’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 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 scope of the proceeding established by FERC is being challenged in 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 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.

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. On May 9, 2016, the district court granted PSCo’s motion to dismiss the lawsuit, essentially concluding that jurisdiction over this dispute resides with the CPUC. It is uncertain whether plaintiffs will appeal this decision. PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms as the line extension payments from developers, for which DRC is seeking a refund, have served to reduce rate base over the period in dispute. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

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Borrowings and Other Financing Instruments

3 Months Ended

Mar. 31, 2016

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 March 31, 2016		Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		1
Maximum amount outstanding	—		34
Weighted average interest rate, computed on a daily basis	N/A		0.41		%
Weighted average interest rate at period end	N/A		N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	700		$	700
Amount outstanding at period end	—			14
Average amount outstanding	25			95
Maximum amount outstanding	154			449
Weighted average interest rate, computed on a daily basis	0.69		%	0.51		%
Weighted average interest rate at period end	N/A			0.60

Letters of Credit— PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2016 and Dec. 31, 2015, there were $4 million 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 March 31, 2016, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700	$	4	$	696

^(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 March 31, 2016 and Dec. 31, 2015.

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Fair Value of Financial Assets and Liabilities

3 Months Ended

Mar. 31, 2016

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 prices.

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 March 31, 2016, 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 March 31, 2016, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months endedMarch 31, 2016 and 2015.

At March 31, 2016, 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 March 31, 2016 and Dec. 31, 2015:

(Amounts in Thousands)(a)(b)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	3,103	684
Million British thermal units of natural gas	28,140	12,515
Gallons of vehicle fuel	48	63

^(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 months ended March 31, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2016
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	402	(a)	$	—		$	—
Vehicle fuel and other commodity	(3		)	—			25		(b)	—			—
Total	$	(3	)	$	—		$	427		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	17		(c)
Natural gas commodity	—			(1,949		)	—			7,736		(d)	(3,261		)	(d)
Total	$	—		$	(1,949	)	$	—		$	7,736		$	(3,244	)

	Three Months Ended March 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(180	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(8		)	—			11			(b)	—				—
Total	$	(8	)	$	—		$	(169	)		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—			$	189	(c)
Natural gas commodity	—			(174		)	—				(5,605		)	(d)	5,460		(d)
Total	$	—		$	(174	)	$	—			$	(5,605	)		$	5,649

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

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

^(d)  Amounts for the three months endedMarch 31, 2016 and 2015 included an immaterial amount 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. The remaining derivative settlement gains and losses for the three months endedMarch 31, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the three months ended March 31, 2016 and 2015. 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 March 31, 2016, three of PSCo’s 10 most significant counterparties, comprising $1.1 million or 1 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Six of the 10 most significant counterparties, comprising $32.7 million or 35 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 $8.5 million or 9 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Nine 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 March 31, 2016 and Dec. 31, 2015, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of PSCo were downgraded below investment grade.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2016 and Dec. 31, 2015.

Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at March 31, 2016:

	March 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	891	$	2,643	$	—	$	3,534	$	(3,034	)	$	500
Total current derivative assets	$	891	$	2,643	$	—	$	3,534	$	(3,034	)	500
PPAs (a)												1,716
Current derivative instruments												$	2,216
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	50	$	—	$	50	$	—		$	50
Natural gas commodity	—		9		—		9		—			9
Total noncurrent derivative assets	$	—	$	59	$	—	$	59	$	—		59
PPAs (a)												$	3,033
Noncurrent derivative instruments												$	3,092
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	68	$	—	$	68	$	—		$	68
Other derivative instruments:
Commodity trading	1,159		2,270		—		3,429		(3,140		)	289
Natural gas commodity	—		119		—		119		—			119
Other commodity	—		92		—		92		—			92
Total current derivative liabilities	$	1,159	$	2,549	$	—	$	3,708	$	(3,140	)	568
PPAs (a)												5,181
Current derivative instruments												$	5,749
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	25	$	—	$	25	$	—		$	25
Natural gas commodity	—		6		—		6		—			6
Total noncurrent derivative liabilities	$	—	$	31	$	—	$	31	$	—		31
PPAs (a)												11,698
Noncurrent derivative instruments												$	11,729

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2016. At March 31, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $0.1 million. 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, 2015:

	Dec. 31, 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:
Commodity trading	$	137	$	351	$	—	$	488	$	(324	)	$	164
Natural gas commodity	—		352		—		352		(286		)	66
Total current derivative assets	$	137	$	703	$	—	$	840	$	(610	)	230
PPAs (a)												1,715
Current derivative instruments												$	1,945
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	16	$	—	$	16	$	—		$	16
Total noncurrent derivative assets	$	—	$	16	$	—	$	16	$	—		16
PPAs (a)												$	3,462
Noncurrent derivative instruments												$	3,478
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	92	$	—	$	92	$	—		$	92
Other derivative instruments:
Commodity trading	34		325		—		359		(324		)	35
Natural gas commodity	—		3,850		—		3,850		(286		)	3,564
Total current derivative liabilities	$	34	$	4,267	$	—	$	4,301	$	(610	)	3,691
PPAs (a)												5,190
Current derivative instruments												$	8,881
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	33	$	—	$	33	$	—		$	33
Total noncurrent derivative liabilities	$	—	$	33	$	—	$	33	$	—		33
PPAs (a)												12,987
Noncurrent derivative instruments												$	13,020

^(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, 2015. At Dec. 31, 2015, 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 months endedMarch 31, 2016 and 2015.

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three months ended March 31, 2016 and 2015.

Fair Value of Long-Term Debt

As of March 31, 2016 and Dec. 31, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,104,255	$	4,552,330	$	4,105,596	$	4,376,875

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of March 31, 2016 and Dec. 31, 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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Other Income, Net

3 Months Ended

Mar. 31, 2016

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	141		$	233
Other nonoperating income	333			777
Insurance policy expense	(25		)	(323		)
Other income, net	$	449		$	687

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Segment Information

3 Months Ended

Mar. 31, 2016

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 March 31, 2016
Operating revenues (a)(b)	$	717,462	$	328,494	$	11,885	$	—		$	1,057,841
Intersegment revenues	81		45		—		(126		)	—
Total revenues	$	717,543	$	328,539	$	11,885	$	(126	)	$	1,057,841
Net income	$	72,536	$	40,890	$	2,448	$	—		$	115,874

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2015
Operating revenues (a)(b)	$	749,461	$	373,203	$	12,786		$	—		$	1,135,450
Intersegment revenues	88		41		—			(129		)	—
Total revenues	$	749,549	$	373,244	$	12,786		$	(129	)	$	1,135,450
Net income (loss)	$	74,669	$	36,623	$	(326	)	$	—		$	110,966

^(a)    Operating revenues include $2 million of affiliate electric revenue for the three months ended March 31, 2016 and 2015.

^(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended March 31, 2016 and 2015.

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Benefit Plans and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2016

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 March 31
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,466		$	7,065		$	192		$	232
Interest cost	13,849			12,714			4,518			4,375
Expected return on plan assets	(17,692		)	(18,148		)	(5,575		)	(5,951		)
Amortization of prior service credit	(807		)	(784		)	(1,562		)	(1,562		)
Amortization of net loss	6,693			9,094			483			619
Net periodic benefit cost (credit)	8,509			9,941			(1,944		)	(2,287		)
Credits (costs) not recognized due to the effects of regulation	766			(366		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	9,275		$	9,575		$	(1,944	)	$	(2,287	)

In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans, of which $16.8 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2016.

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Other Comprehensive Income

3 Months Ended

Mar. 31, 2016

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(23,836	)	$	—		$	(23,836	)
Other comprehensive loss before reclassifications	(2		)	(219		)	(221		)
Losses reclassified from net accumulated other comprehensive loss	264			—			264
Net current period other comprehensive income (loss)	262			(219		)	43
Accumulated other comprehensive loss at March 31	$	(23,574	)	$	(219	)	$	(23,793	)

	Three Months Ended March 31, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)
Other comprehensive loss before reclassifications	(5		)
Gains reclassified from net accumulated other comprehensive loss	(105		)
Net current period other comprehensive loss	(110		)
Accumulated other comprehensive loss at March 31	$	(23,988	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	402		(a)	$	(180	)	(a)
Vehicle fuel derivatives	25			(b)	11			(b)
Total, pre-tax	427				(169		)
Tax (benefit) expense	(163		)		64
Total amounts reclassified, net of tax	$	264			$	(105	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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Selected Balance Sheet Data (Tables)

3 Months Ended

Mar. 31, 2016

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	279,677		$	321,004
Less allowance for bad debts	(19,456		)	(20,122		)
	$	260,221		$	300,882

Inventories

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	58,766	$	58,128
Fuel	71,506		78,586
Natural gas	35,125		68,848
	$	165,397	$	205,562

Property, Plant and Equipment, Net

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	11,888,887		$	11,856,126
Natural gas plant	3,490,099			3,420,249
Common and other property	863,165			862,840
Plant to be retired (a)	34,607			38,249
Construction work in progress	452,786			408,963
Total property, plant and equipment	16,729,544			16,586,427
Less accumulated depreciation	(4,459,591		)	(4,414,216		)
	$	12,269,953		$	12,172,211

^(a)  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.

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.6	$	2.4
Unrecognized tax benefit — Temporary tax positions	15.0		15.0
Total unrecognized tax benefit	$	17.6	$	17.4

Tax Benefits Associated with NOL and Tax Credit Carryforwards

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

(Millions of Dollars)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(4.6	)	$	(4.3	)

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Borrowings and Other Financing Instruments (Tables)

3 Months Ended

Mar. 31, 2016

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At March 31, 2016, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700	$	4	$	696

^(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 March 31, 2016		Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		1
Maximum amount outstanding	—		34
Weighted average interest rate, computed on a daily basis	N/A		0.41		%
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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	700		$	700
Amount outstanding at period end	—			14
Average amount outstanding	25			95
Maximum amount outstanding	154			449
Weighted average interest rate, computed on a daily basis	0.69		%	0.51		%
Weighted average interest rate at period end	N/A			0.60

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Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2016

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 March 31, 2016 and Dec. 31, 2015:

(Amounts in Thousands)(a)(b)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	3,103	684
Million British thermal units of natural gas	28,140	12,515
Gallons of vehicle fuel	48	63

^(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 months ended March 31, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2016
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	402	(a)	$	—		$	—
Vehicle fuel and other commodity	(3		)	—			25		(b)	—			—
Total	$	(3	)	$	—		$	427		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	17		(c)
Natural gas commodity	—			(1,949		)	—			7,736		(d)	(3,261		)	(d)
Total	$	—		$	(1,949	)	$	—		$	7,736		$	(3,244	)

	Three Months Ended March 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(180	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(8		)	—			11			(b)	—				—
Total	$	(8	)	$	—		$	(169	)		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—			$	189	(c)
Natural gas commodity	—			(174		)	—				(5,605		)	(d)	5,460		(d)
Total	$	—		$	(174	)	$	—			$	(5,605	)		$	5,649

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

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

^(d)  Amounts for the three months endedMarch 31, 2016 and 2015 included an immaterial amount 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. The remaining derivative settlement gains and losses for the three months endedMarch 31, 2016 and 2015 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 March 31, 2016:

	March 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	891	$	2,643	$	—	$	3,534	$	(3,034	)	$	500
Total current derivative assets	$	891	$	2,643	$	—	$	3,534	$	(3,034	)	500
PPAs (a)												1,716
Current derivative instruments												$	2,216
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	50	$	—	$	50	$	—		$	50
Natural gas commodity	—		9		—		9		—			9
Total noncurrent derivative assets	$	—	$	59	$	—	$	59	$	—		59
PPAs (a)												$	3,033
Noncurrent derivative instruments												$	3,092
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	68	$	—	$	68	$	—		$	68
Other derivative instruments:
Commodity trading	1,159		2,270		—		3,429		(3,140		)	289
Natural gas commodity	—		119		—		119		—			119
Other commodity	—		92		—		92		—			92
Total current derivative liabilities	$	1,159	$	2,549	$	—	$	3,708	$	(3,140	)	568
PPAs (a)												5,181
Current derivative instruments												$	5,749
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	25	$	—	$	25	$	—		$	25
Natural gas commodity	—		6		—		6		—			6
Total noncurrent derivative liabilities	$	—	$	31	$	—	$	31	$	—		31
PPAs (a)												11,698
Noncurrent derivative instruments												$	11,729

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2016. At March 31, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $0.1 million. 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, 2015:

	Dec. 31, 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:
Commodity trading	$	137	$	351	$	—	$	488	$	(324	)	$	164
Natural gas commodity	—		352		—		352		(286		)	66
Total current derivative assets	$	137	$	703	$	—	$	840	$	(610	)	230
PPAs (a)												1,715
Current derivative instruments												$	1,945
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	16	$	—	$	16	$	—		$	16
Total noncurrent derivative assets	$	—	$	16	$	—	$	16	$	—		16
PPAs (a)												$	3,462
Noncurrent derivative instruments												$	3,478
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	92	$	—	$	92	$	—		$	92
Other derivative instruments:
Commodity trading	34		325		—		359		(324		)	35
Natural gas commodity	—		3,850		—		3,850		(286		)	3,564
Total current derivative liabilities	$	34	$	4,267	$	—	$	4,301	$	(610	)	3,691
PPAs (a)												5,190
Current derivative instruments												$	8,881
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	33	$	—	$	33	$	—		$	33
Total noncurrent derivative liabilities	$	—	$	33	$	—	$	33	$	—		33
PPAs (a)												12,987
Noncurrent derivative instruments												$	13,020

^(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, 2015. At Dec. 31, 2015, 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 March 31, 2016 and Dec. 31, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,104,255	$	4,552,330	$	4,105,596	$	4,376,875

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

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Other Income, Net (Tables)

3 Months Ended

Mar. 31, 2016

Other Income and Expenses [Abstract]

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	141		$	233
Other nonoperating income	333			777
Insurance policy expense	(25		)	(323		)
Other income, net	$	449		$	687

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Results from Operations by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2016
Operating revenues (a)(b)	$	717,462	$	328,494	$	11,885	$	—		$	1,057,841
Intersegment revenues	81		45		—		(126		)	—
Total revenues	$	717,543	$	328,539	$	11,885	$	(126	)	$	1,057,841
Net income	$	72,536	$	40,890	$	2,448	$	—		$	115,874

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2015
Operating revenues (a)(b)	$	749,461	$	373,203	$	12,786		$	—		$	1,135,450
Intersegment revenues	88		41		—			(129		)	—
Total revenues	$	749,549	$	373,244	$	12,786		$	(129	)	$	1,135,450
Net income (loss)	$	74,669	$	36,623	$	(326	)	$	—		$	110,966

^(a)    Operating revenues include $2 million of affiliate electric revenue for the three months ended March 31, 2016 and 2015.

^(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended March 31, 2016 and 2015.

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Benefit Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,466		$	7,065		$	192		$	232
Interest cost	13,849			12,714			4,518			4,375
Expected return on plan assets	(17,692		)	(18,148		)	(5,575		)	(5,951		)
Amortization of prior service credit	(807		)	(784		)	(1,562		)	(1,562		)
Amortization of net loss	6,693			9,094			483			619
Net periodic benefit cost (credit)	8,509			9,941			(1,944		)	(2,287		)
Credits (costs) not recognized due to the effects of regulation	766			(366		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	9,275		$	9,575		$	(1,944	)	$	(2,287	)

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2016

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 months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(23,836	)	$	—		$	(23,836	)
Other comprehensive loss before reclassifications	(2		)	(219		)	(221		)
Losses reclassified from net accumulated other comprehensive loss	264			—			264
Net current period other comprehensive income (loss)	262			(219		)	43
Accumulated other comprehensive loss at March 31	$	(23,574	)	$	(219	)	$	(23,793	)

	Three Months Ended March 31, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)
Other comprehensive loss before reclassifications	(5		)
Gains reclassified from net accumulated other comprehensive loss	(105		)
Net current period other comprehensive loss	(110		)
Accumulated other comprehensive loss at March 31	$	(23,988	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	402		(a)	$	(180	)	(a)
Vehicle fuel derivatives	25			(b)	11			(b)
Total, pre-tax	427				(169		)
Tax (benefit) expense	(163		)		64
Total amounts reclassified, net of tax	$	264			$	(105	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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Accounting Pronouncements Debt Issuance Costs (Details) - Accounting Standards Update 2015-03 - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Long-term Debt
Debt Instrument [Line Items]
Reclassification of deferred debt issuance costs, net	$ 26.0	$ 26.6
Other Noncurrent Assets
Debt Instrument [Line Items]
Reclassification of deferred debt issuance costs, net		$ (26.6)

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Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$ 279,677	$ 321,004
Less allowance for bad debts	(19,456)	(20,122)
Accounts receivable, net	$ 260,221	$ 300,882

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Inventories	$ 165,397	$ 205,562
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	58,766	58,128
Fuel
Public Utilities, Inventory [Line Items]
Inventories	71,506	78,586
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 35,125	$ 68,848

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 16,729,544	$ 16,586,427
Less accumulated depreciation		(4,459,591)	(4,414,216)
Property, plant and equipment, net		12,269,953	12,172,211
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		11,888,887	11,856,126
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		3,490,099	3,420,249
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		863,165	862,840
Plant to be retired
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	[1]	34,607	38,249
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 452,786	$ 408,963

[1] (a) 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.

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Income Taxes (Details) - USD ($)	3 Months Ended	9 Months Ended
	Mar. 31, 2016	Sep. 30, 2015	Sep. 30, 2012	Dec. 31, 2015
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions	$ 2,600,000			$ 2,400,000
Unrecognized tax benefit — Temporary tax positions	15,000,000			15,000,000
Total unrecognized tax benefit	17,600,000			17,400,000
NOL and tax credit carryforwards	(4,600,000)			(4,300,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	11,000,000
Amounts accrued for penalties related to unrecognized tax benefits	0			$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination		2012 and 2013	2010 and 2011
Year of carryback claim under examination			2009
Potential Tax Adjustments	$ 14,000,000
State Jurisdiction (Colorado)
Tax Audits [Abstract]
Earliest year subject to examination	2009

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Rate Matters (Details) - USD ($) $ in Millions		3 Months Ended
	Apr. 29, 2016	Mar. 31, 2016
CPUC Proceeding - Annual Electric Earnings Test
Rate Matters [Abstract]
Public Utilities, Return On Equity Threshold For Earnings Sharing For 2015 Through 2017		9.83%
Subsequent Event | 2015 Electric Earnings Test
Rate Matters [Abstract]
Public Utilities, Refund to Customers Due to Annual Earnings Test	$ 14.9

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Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Purchased Power Agreements [Abstract]
Generating capacity under long term purchased power agreements	1,802	1,802
Purchase Power Agreement Duration, Maximum	2032	2032

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Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	1 Months Ended	3 Months Ended
	Feb. 29, 2016	Mar. 31, 2016 USD ($)
Regional Haze Rules
Environmental Requirements [Abstract]
Amount spent on installation of emission controls		$ 75.2
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 years unclassifiable areas will be monitored	3 years
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

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Commitments and Contingencies, Legal Contingencies (Details)	3 Months Ended
	Mar. 31, 2016 USD ($) Factor
Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Estimated City of Seattle's claim for refunds not including interest	$ 28,000,000
Number of factors considered in assessment | Factor	2
Accrual for legal contingency	$ 0
Line Extension Disputes
Legal Contingencies [Abstract]
Accrual for legal contingency	0
Maximum | Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Minimum amount of damages claimed by plaintiff	50,000,000
Minimum | Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Minimum amount of damages claimed by plaintiff	$ 34,000,000

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 14,000,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000,000	250,000,000
Amount outstanding at period end	0	0
Average amount outstanding	0	1,000,000
Maximum amount outstanding	0	$ 34,000,000
Weighted average interest rate, computed on a daily basis (percentage)		0.41%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	700,000,000	$ 700,000,000
Amount outstanding at period end	0	14,000,000
Average amount outstanding	25,000,000	95,000,000
Maximum amount outstanding	$ 154,000,000	$ 449,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.69%	0.51%
Weighted average interest rate at period end (percentage)		0.60%

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 14,000,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	4,000,000	$ 4,000,000
Credit Facility
Line of Credit Facility [Line Items]
Direct advances on the credit facility outstanding	$ 0
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

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Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility	3 Months Ended
	Mar. 31, 2016 USD ($)
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date	Oct. 31, 2019
Credit Facility	$ 700,000,000	[1]
Drawn	4,000,000	[2]
Available	696,000,000
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.

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions		Mar. 31, 2016 USD ($) MMBTU MWh gal Counterparty	Dec. 31, 2015 MMBTU MWh gal
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 | Municipal or Cooperative Entities or Other Utilities [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		9
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		3
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 1.1
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		1.00%
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		6
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 32.7
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		35.00%
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		$ 8.5
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		9.00%
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1],[2]	3,103	684
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]	28,140	12,515
Vehicle Fuel Commodity (in gallons)
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | gal	[1],[2]	48	63

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

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

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges		$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions		0	0
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		(3,000)	(8,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		427,000	(169,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income		0	0
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
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[1]	402,000	(180,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income		0	0
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		(3,000)	(8,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[2]	25,000	11,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income		0	0
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
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(1,949,000)	(174,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		7,736,000	(5,605,000)
Pre-tax gains (losses) recognized during the period in income		(3,244,000)	5,649,000
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	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income	[3]	17,000	189,000
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
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(1,949,000)	(174,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	[4]	7,736,000	(5,605,000)
Pre-tax gains (losses) recognized during the period in income	[4]	$ (3,261,000)	$ 5,460,000

[1] Recorded to interest charges.

[2] Recorded to O&M expenses.

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

[4] Amounts for the three months ended March 31, 2016 and 2015 included an immaterial amount 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. The remaining derivative settlement gains and losses for the three months ended March 31, 2016 and 2015 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

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
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

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Mar. 31, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		100
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		2,216		1,945
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3,092		3,478
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		5,749		8,881
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		11,729		13,020
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		500		230
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		500		164
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				66
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		59		16
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		50		16
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		9
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		568
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		68		92
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				3,691
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		289		35
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		119		3,564
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		92
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		31		33
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		25		33
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		6
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		891		137
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		891		137
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
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,159		34
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 | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,159		34
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 | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas 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		2,643		703
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		2,643		351
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				352
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		59		16
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		50		16
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		9
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,549		4,267
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		68		92
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,270		325
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		119		3,850
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		92
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		31		33
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		25		33
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		6
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 | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		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 | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | 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 | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas 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		3,534		840
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3,534		488
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				352
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		59		16
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		50		16
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		9
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		3,708		4,301
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		68		92
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		3,429		359
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		119		3,850
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		92
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		31		33
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		25		33
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		6
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(3,034)	[1]	(610)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(3,034)	[1]	(324)	[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	[2]			(286)
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	0
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(3,140)	[1]	(610)	[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 | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(3,140)	[1]	(324)	[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		0	[1]	(286)	[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 | Other Derivative Instruments | Commodity Trading
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
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		1,716	[3]	1,715	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3,033	[3]	3,462	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		5,181	[3]	5,190	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		$ 11,698	[3]	$ 12,987	[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 March 31, 2016. At March 31, 2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $0.1 million. 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, 2015. At Dec. 31, 2015, 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.

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Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Transfers into Level 3	$ 0	$ 0
Transfers out of Level 3	$ 0	$ 0

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	[1]	$ 4,104,255	$ 4,105,596
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	[1]	$ 4,552,330	$ 4,376,875

[1] Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

XML

Other Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Other Income and Expenses [Abstract]
Interest income	$ 141	$ 233
Other nonoperating income	333	777
Insurance policy expense	(25)	(323)
Other income, net	$ 449	$ 687

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Segment Information (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues		$ 1,057,841	$ 1,135,450
Net income (loss)		115,874	110,966
Affiliate electric revenue		2,000	2,000
Affiliate other revenue		1,000	1,000
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues		717,543	749,549
Net income (loss)		72,536	74,669
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues		328,539	373,244
Net income (loss)		40,890	36,623
All Other
Segment Reporting Information [Line Items]
Operating revenues		11,885	12,786
Net income (loss)		2,448	(326)
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	[1],[2]	1,057,841	1,135,450
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	[2]	717,462	749,461
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues		328,494	373,203
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	[1]	11,885	12,786
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues		(126)	(129)
Net income (loss)		0	0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues		81	88
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues		45	41
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues		$ 0	$ 0

[1] Operating revenues include $1 million of other affiliate revenue for the three months ended March 31, 2016 and 2015.

[2] Operating revenues include $2 million of affiliate electric revenue for the three months ended March 31, 2016 and 2015

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Jan. 31, 2016 USD ($) Plan	Mar. 31, 2016 USD ($)	Mar. 31, 2015 USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 6,466	$ 7,065
Interest cost		13,849	12,714
Expected return on plan assets		(17,692)	(18,148)
Amortization of prior service credit		(807)	(784)
Amortization of net loss		6,693	9,094
Net periodic benefit cost (credit)		8,509	9,941
Costs not recognized due to the effects of regulation		766	(366)
Net benefit cost (credit) recognized for financial reporting		9,275	9,575
Total contributions to the pension plans during the period	$ 16,800
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		192	232
Interest cost		4,518	4,375
Expected return on plan assets		(5,575)	(5,951)
Amortization of prior service credit		(1,562)	(1,562)
Amortization of net loss		483	619
Net periodic benefit cost (credit)		(1,944)	(2,287)
Costs not recognized due to the effects of regulation		0	0
Net benefit cost (credit) recognized for financial reporting		$ (1,944)	$ (2,287)
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Total contributions to the pension plans during the period	$ 125,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4

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Other Comprehensive Income (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		$ (23,836)
Other comprehensive income (loss) before reclassifications		(221)
Gains reclassified from net accumulated other comprehensive loss		264
Net current period other comprehensive loss		43
Accumulated other comprehensive loss at end of period		(23,793)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses		178,386	$ 182,417
Total, pre-tax		(183,819)	(176,901)
Tax (benefit) expense		67,945	65,935
Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		0
Other comprehensive income (loss) before reclassifications		(219)
Gains reclassified from net accumulated other comprehensive loss		0
Net current period other comprehensive loss		(219)
Accumulated other comprehensive loss at end of period		(219)
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		(23,836)	(23,878)
Other comprehensive income (loss) before reclassifications		(2)	(5)
Gains reclassified from net accumulated other comprehensive loss		264	(105)
Net current period other comprehensive loss		262	(110)
Accumulated other comprehensive loss at end of period		(23,574)	(23,988)
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		427	(169)
Tax (benefit) expense		(163)	64
Total, net of tax		264	(105)
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]	402	(180)
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]	$ 25	$ 11

[1] Included in interest charges.

[2] Included in O&M expenses