10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2014

or

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

Commission File Number: 001-3280

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

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

Registrant’s telephone number, including area code: (303) 571-7511

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes o No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes x No

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 if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

As of Feb. 20, 2015, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Xcel Energy Inc.’s Definitive Proxy Statement for its 2015 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

Public Service Company of Colorado meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with reduced disclosure format permitted by General Instruction I(2).

TABLE OF CONTENTS

Index

PART I
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	8
Fuel Sources	8
Renewable Energy Sources	9
Wholesale Commodity Marketing Operations	9
Summary of Recent Regulatory Developments	10
Electric Operating Statistics	11
NATURAL GAS UTILITY OPERATIONS	12
Overview	12
Public Utility Regulation	12
Capability and Demand	13
Natural Gas Supply and Costs	13
Natural Gas Operating Statistics	14
GENERAL	14
ENVIRONMENTAL MATTERS	15
EMPLOYEES	15
Item 1A — Risk Factors	15
Item 1B — Unresolved Staff Comments	24
Item 2 — Properties	25
Item 3 — Legal Proceedings	26
Item 4 — Mine Safety Disclosures	26
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6 — Selected Financial Data	26
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	29
Item 8 — Financial Statements and Supplementary Data	31
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	82
Item 9A — Controls and Procedures	82
Item 9B — Other Information	82
PART III
Item 10 — Directors, Executive Officers and Corporate Governance	82
Item 11 — Executive Compensation	82
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	82
Item 13 — Certain Relationships and Related Transactions, and Director Independence	82
Item 14 — Principal Accountant Fees and Services	83
PART IV
Item 15 — Exhibits, Financial Statement Schedules	84
SIGNATURES	88

This Form 10-K is filed by PSCo. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NCE	New Century Energies, Inc.
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
PSRI	P.S.R. Investments, Inc.
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WYCO	WYCO Development LLC
Xcel Energy	Xcel Energy Inc. and subsidiaries
Federal and State Regulatory Agencies
CFTC	Commodity Futures Trading Commission
CPUC	Colorado Public Utilities Commission
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOI	United States Department of the Interior
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
NERC	North American Electric Reliability Corporation
SEC	Securities and Exchange Commission
Electric, Purchased Gas and Resource Adjustment Clauses
DSM	Demand side management
DSMCA	Demand side management cost adjustment
ECA	Retail electric commodity adjustment
ERP	Electric resource plan
GCA	Gas cost adjustment
PCCA	Purchased capacity cost adjustment
PSIA	Pipeline system integrity adjustment
QSP	Quality of service plan
RES	Renewable energy standard
RESA	Renewable energy standard adjustment
SCA	Steam cost adjustment
TCA	Transmission cost adjustment
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
ALJ	Administrative law judge
APBO	Accumulated postretirement benefit obligation
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
BART	Best available retrofit technology
C&I	Commercial and Industrial
CAA	Clean Air Act
CACJA	Clean Air Clean Jobs Act
CO2	Carbon dioxide

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CPCN	Certificate of public convenience and necessity
CWIP	Construction work in progress
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTY	Forecast test year
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
HTY	Historic test year
JOA	Joint operating agreement
MGP	Manufactured gas plant
MISO	Midcontinent Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.
NOL	Net operating loss
NOx	Nitrogen oxide
NOV	Notice of violation
NSPS	New source performance standard
O&M	Operating and maintenance
OCC	Office of Consumer Counsel
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PJM	PJM Interconnection, LLC
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
PV	Photovoltaic
REC	Renewable energy credit
RFP	Request for proposal
ROE	Return on equity
ROFR	Right of first refusal
RPS	Renewable portfolio standards
RTO	Regional Transmission Organization
SCR	Selective catalytic reduction
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services
Measurements
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours
GWh	Gigawatt hours

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COMPANY OVERVIEW

PSCo was incorporated in 1924 under the laws of Colorado.  PSCo is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado.  The wholesale customers served by PSCo comprised approximately 11 percent of its total KWh sold in 2014.  PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.  PSCo provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 1.3 million customers.  All of PSCo’s retail electric operating revenues were derived from operations in Colorado during 2014.  Although PSCo’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large commercial and industrial electric sales include the following industries:  fabricated metal products, communications and oil and gas extraction.  For small commercial and industrial customers, significant electric retail sales include the following industries:  real estate and dining establishments.  Generally, PSCo’s earnings contribute approximately 45 percent to 55 percent of Xcel Energy’s consolidated net income.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, both of which own certain real estate interests; and Green and Clear Lakes Company, which owns water rights and certain real estate interests.  PSCo also owns PSRI, which held certain former employees’ life insurance policies.  PSCo also holds a controlling interest in several other relatively small ditch and water companies.

PSCo conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. See Note 15 to the consolidated financial statements for further discussion relating to comparative segment revenues, net income and related financial information.

PSCo’s corporate strategy focuses on four core objectives: improving utility performance; driving operational excellence; providing options and solutions to customers; and investing for the future.

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction— PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo is regulated by the FERC with respect to its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.

Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms— PSCo has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:

• ECA — The ECA recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly.

• PCCA — The PCCA recovers purchased capacity payments.

• SCA — The SCA recovers the difference between PSCo’s actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised annually in January, as well as on an interim basis.

• DSMCA — The DSMCA recovers DSM, interruptible service option credit costs and performance initiatives for achieving various energy savings goals.

• RESA — The RESA recovers the incremental costs of compliance with the RES with a maximum of two percent of the customer’s total bill.

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• Wind Energy Service — Wind Energy Service is a premium service for customers who voluntarily choose to pay an additional charge for renewable resources.

• TCA — The TCA recovers costs associated with transmission investment outside of rate cases.

• CACJA — As part of its pending electric rate case, PSCo proposed to establish a CACJA rider, retroactive to Jan. 1, 2015, to recover costs associated with implementing its compliance plan under the CACJA.

PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. PSCo’s wholesale customers have agreed to pay the full cost of certain renewable energy purchase and generation costs through a fuel clause and in exchange receive RECs associated with those resources. The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.

QSP Requirements— The CPUC established an electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service. PSCo monitors and records, as necessary, an estimated customer refund obligation under the QSP. The CPUC extended the terms of the current QSP through 2015.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2015, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2012	2013	2014	2015 Forecast
PSCo	6,689	6,678	6,152	6,475

The peak demand for PSCo’s system typically occurs in the summer. The 2014 uninterrupted system peak demand for PSCo occurred on July 7, 2014. The 2014 system peak demand was lower due to reduced wholesale loads and cooler summer weather. In 2013 Comanche Unit 3 was off-line, which increased PSCo’s system load by approximately 250 MW for the backup power provided by PSCo to the joint owners. The forecast of 2015 system peak assumes normal weather conditions.

Energy Sources and Related Transmission Initiatives

PSCo expects to meet its system capacity requirements through existing electric generating stations, power purchases, new generation facilities, DSM options and phased expansion of existing generation at select power plants.

Purchased Power— PSCo has contracts to purchase power from other utilities and independent power producers.  Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased. PSCo also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost.

Purchased Transmission Services— In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to PSCo’s customers.

ERP and All-Source Solicitation— In 2013, PSCo issued an All-Source RFP for 250 MW of generation by the end of 2018. PSCo also issued a separate wind RFP for PPAs only.

The CPUC provided final approval to PSCo’s plan in December 2013, which includes the following:

• The addition of 450 MW of wind generation PPAs, which are expected to be operational in 2015. These additional PPAs will bring the installed wind capacity on PSCo’s system in Colorado to 2,650 MW;

• The addition of 170 MW of utility-scale solar generation PPAs, which are expected to be operational in 2016. PSCo has approximately 80 MW of utility-scale solar and approximately 188 MW of customer-sited solar generation;

• The addition of 317 MW of natural gas fired generation PPAs, which will come from existing power plants;

• The accelerated retirements of the coal-fired Arapahoe Unit 3 (45 MW) and Unit 4 (109 MW), which occurred in 2013; and

• The continued operation of Cherokee generating station’s Unit 4 as a natural gas facility after 2017.

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In addition, PSCo continues to execute on the remaining aspects of CACJA compliance including the construction of a new natural gas fired combined cycle unit at Cherokee generating station and the addition of emissions controls at the Pawnee and Hayden stations. PSCo also expects to retire the Cherokee Unit 3 and Valmont Unit 5 coal-fired power plants by the end of 2015 and 2017, respectively.

Brush, Colo. to Castle Pines, Colo. 345 KV Transmission Line — In March 2014, PSCo filed with the CPUC for a CPCN to construct a new 345 KV transmission line originating from Pawnee Station, near Brush, Colo. and terminating at the Daniels Park substation, near Castle Pines, Colo. The estimated cost of the project is $178 million. In September 2014, PSCo entered into a partial settlement agreement with the CPUC Staff supporting the grant of a CPCN for the line. The OCC has opposed the CPCN. In November 2014, the ALJ issued a recommended decision approving the CPCN, but delaying construction until May 2020. PSCo filed exceptions to the recommended decision, requesting clarification and reconsideration to commence certain portions of the project in 2015. A CPUC decision is anticipated in the first quarter of 2015.

Thornton, Colo. Substation Project — In October 2014, PSCo filed with the CPUC for a CPCN to construct a new substation to serve growing load in and around Thornton, Colo. to be placed into service in July 2016.  The estimated cost of the project is approximately $34 million.  The OCC and the City of Thornton have intervened in the CPCN proceeding.  In November 2014, the matter was referred to an ALJ for hearing procedures.  In January 2015, PSCo and the OCC filed a settlement agreement with the CPUC requesting approval of the CPCN. The City of Thornton did not oppose the settlement. An evidentiary hearing was held in February 2015 and a CPUC decision is anticipated in the first quarter of 2015.

Boulder, Colo. Municipalization — PSCo’s franchise agreement with the City of Boulder (Boulder) expired in December 2010. In November 2011, a ballot measure was passed which authorized the formation and operation of a municipal utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage. In May 2014, the Boulder City Council passed an ordinance to establish an electric utility.

In 2013, the CPUC ruled that it has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine certain system separation matters as well as what facilities need to be constructed to ensure reliable service. The CPUC has declared that it should make its determinations prior to any eminent domain actions. In January 2014, Boulder appealed this ruling to the Boulder District Court. In January 2015, the Boulder District Court affirmed the CPUC decision.

Boulder sent PSCo an offer of $128 million for certain portions of PSCo’s transmission and distribution business. PSCo has notified Boulder that its offer was deficient. Under Colorado law, a condemning entity must pay the owner fair market value for the taking of and damages to the remainder of the property.

In July 2014, Boulder filed a petition for condemnation in the Boulder District Court. PSCo filed a motion to dismiss the petition based upon the CPUC’s ruling that it must determine the appropriate system separations prior to Boulder filing its condemnation case. PSCo’s motion to dismiss was granted in February 2015. This decision does not prevent Boulder from filing another condemnation petition if it obtains CPUC approval of a separation plan.

In August 2014, PSCo filed a petition with the FERC requesting an order requiring that Boulder’s attempt to acquire PSCo’s transmission and distribution facilities by condemnation requires prior FERC approval under the Federal Power Act. In December 2014, the FERC issued an order granting PSCo’s petition.

If Boulder proceeds with another condemnation petition and were to succeed in the eminent domain proceeding, PSCo would seek to obtain full compensation for the business and its associated property taken by Boulder, as well as for all damages resulting to PSCo and its system. PSCo would also seek appropriate compensation for stranded costs with the FERC.

RES Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales are supplied by renewable energy by 2020 and includes a distributed generation standard. In July 2013, PSCo filed its 2014 RES compliance plan. In July 2014, the ALJ issued a recommended decision accepting PSCo’s compliance plan with modifications. The CPUC approved the recommended decision with modifications in December 2014. PSCo subsequently requested additional adjustments to the CPUC’s decision, which were granted through an order issued in February 2015.

Net Metering Standard — In a filing, PSCo proposed to track and quantify the system costs that are not avoided by distributed solar generation, which PSCo has defined as a “net metering incentive,” for purposes of equitably recovering costs between customers. The CPUC assigned the net metering issue to its own docket. A CPUC decision is anticipated in the third quarter of 2015.

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Steam System Package Boilers and Regulatory Plan— In December 2014, PSCo filed the results of a steam survey along with both a short-term plan and a long-term plan for the steam system consisting of a request for a conditional CPCN to construct either one or two boilers for its steam utility, dependent on the next two seasons of winter peaking capacity. A decision is anticipated in the third quarter of 2015.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

	Coal				Natural Gas				Weighted Average Owned Fuel Cost
PSCo Generating Plants	Cost		Percent		Cost		Percent
2014	$	1.82	75	%	$	5.32	25	%	$	2.68
2013	1.84		80		4.86		20		2.45
2012	1.77		78		4.25		22		2.31

The higher cost of natural gas was primarily due to higher market prices from increased demand because of cold weather in early 2014.

See Items 1A and 7 for further discussion of fuel supply and costs.

Fuel Sources

Coal— PSCo normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2014 and 2013 were approximately 36 and 41 days usage, respectively. At Dec. 31, 2014, coal inventories were below optimal levels due to railcar congestion. PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2014 and 2013, PSCo’s coal requirements for existing plants were approximately 10.3 million tons and 11.3 million tons, respectively. The estimated coal requirements for 2015 are approximately 11.0 million tons.

PSCo has contracted for coal supply to provide 96 percent of its estimated coal requirements in 2015, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the first year, 67 percent of requirements in year two, and 33 percent of requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

PSCo has coal transportation contracts that provide for delivery of 100 percent of its coal requirements in 2015 and 2016. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Natural gas— PSCo uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, any remaining forecasted requirements are able to be procured through a liquid spot market. The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company, the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 11 to the consolidated financial statements for further discussion.

Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.

• At Dec. 31, 2014, PSCo’s commitments related to gas supply contracts, which expire in various years from 2015 through 2023, were approximately $902 million and commitments related to gas transportation and storage contracts, which expire in various years from 2015 through 2060, were approximately $685 million.

• At Dec. 31, 2013, PSCo’s commitments related to gas supply contracts were approximately $1.1 billion and commitments related to gas transportation and storage contracts were approximately $723 million.

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PSCo has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2014, PSCo was in compliance with mandated RPS, which require generation from renewable resources of 12 percent of electric retail sales.

• Renewable energy comprised 21.4 percent and 21.9 percent of PSCo’s total owned and purchased energy for 2014 and 2013, respectively.

• Wind energy comprised 18.9 percent and 19.3 percent of PSCo’s total owned and purchased energy for 2014 and 2013, respectively.

• Hydroelectric, biomass and solar power comprised approximately 2.5 percent and 2.6 percent of PSCo’s total owned and purchased energy for 2014 and 2013.

PSCo also offers customer-focused renewable energy initiatives. Windsource allows customers to purchase a portion or all of their electricity from renewable sources. In 2014, the number of customers utilizing Windsource increased to approximately 41,000 from 37,000 in 2013. Windsource MWh sales declined slightly, due in part to loss of certain commercial customers, from approximately 197,000 MWh in 2013 to 188,000 MWh in 2014.

Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards program. Over 24,000 PV systems with approximately 221 MW of aggregate capacity and over 18,250 PV systems with approximately 188 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2014 and 2013, respectively. In 2014, the first community solar gardens were interconnected in Colorado. As of Dec. 31, 2014, 14 gardens have been completed with 9.6 MW of capacity.

Wind— PSCo acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Colorado. Currently, PSCo has 18 of these agreements in place, with facilities ranging in size from two MW to over 300 MW. PSCo owns and operates the 26 MW Ponnequin Wind Farm in northern Colorado, which has been in service since 1999.

• PSCo had approximately 2,340 MW and 2,170 MW of wind energy on its system at the end of 2014 and 2013, respectively.

• In October 2013, the CPUC approved the addition of 450 MW of Colorado wind generation PPA’s.

• With the new projects, PSCo is anticipated to have approximately 2,592 MW of wind power by 2016. In addition to receiving purchased wind energy under these agreements, PSCo also typically receives wind RECs, which are used to meet state renewable resource requirements.

• The average cost per MWh of wind energy under these contracts was approximately $45 in both 2014 and 2013. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, contracts executed in 2014 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 2014, with certain projects qualifying into future years.

Wholesale Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. See Item 7A for further discussion.

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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 NERC mandatory electric reliability standards.  State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 11 to the accompanying 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 October 2014, the FERC upheld the determination of the long-term growth rate to be used in its new ROE methodology. Several parties sought rehearing of the June 2014 order and therefore the new FERC policy may be subject to additional changes.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued a final ruling, Order 1000, adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. Order 1000 requires:

• The development of tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region;

• The coordination between regions for the development of interregional plans for transmission planning and cost allocation;

• Each public utility transmission provider to amend its Open Access Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; and

• The removal of ROFR provisions from FERC-jurisdictional wholesale transmission contracts and tariffs that presently grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area.

The jurisdictional WestConnect utilities, including PSCo, have submitted multiple compliance filings with the FERC to implement the Order 1000 requirements. Some of the new compliance provisions that were filed have already been approved but others remain under review by the FERC. The ultimate impact of Order 1000 on future PSCo transmission investment is not known at this time.

NERC Critical Infrastructure Protection (CIP) Requirements — The FERC has approved version 5 of NERC’s CIP standards. Requirements must be applied to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. PSCo is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

NERC Physical Security Requirements — In November 2014, the FERC issued its final rule approving NERC’s proposed CIP standard related to physical security for bulk electric system facilities. The new standard will become enforceable in October 2015 with staggered milestone deliverable dates through 2016.  PSCo is currently in the process of developing and performing the initial risk assessment in accordance with the requirements of the standard, which will provide a basis to estimate the cost of protections necessary to meet the standard.  The additional cost for compliance is anticipated to be recoverable through rates.

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Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2014			2013			2012
Electric sales (Millions of KWh)
Residential	9,009			9,266			9,193
Large commercial and industrial	6,712			6,652			6,649
Small commercial and industrial	12,709			12,716			12,711
Public authorities and other	241			227			233
Total retail	28,671			28,861			28,786
Sales for resale	3,664			4,467			4,464
Total energy sold	32,335			33,328			33,250
Number of customers at end of period
Residential	1,202,621			1,187,308			1,176,356
Large commercial and industrial	334			328			334
Small commercial and industrial	156,809			155,643			154,575
Public authorities and other	53,824			53,724			54,396
Total retail	1,413,588			1,397,003			1,385,661
Wholesale	23			23			20
Total customers	1,413,611			1,397,026			1,385,681
Electric revenues (Thousands of Dollars)
Residential	$	1,081,092		$	1,083,928		$	1,015,497
Large commercial and industrial	462,449			437,556			401,481
Small commercial and industrial	1,267,023			1,218,856			1,136,636
Public authorities and other	54,555			52,676			49,900
Total retail	2,865,119			2,793,016			2,603,514
Wholesale	211,241			228,041			210,627
Other electric revenues	49,577			60,114			155,758
Total electric revenues	$	3,125,937		$	3,081,171		$	2,969,899
KWh sales per retail customer	20,282			20,659			20,774
Revenue per retail customer	$	2,027		$	1,999		$	1,879
Residential revenue per KWh	12.00		¢	11.70		¢	11.05		¢
Large commercial and industrial revenue per KWh	6.89			6.58			6.04
Small commercial and industrial revenue per KWh	9.97			9.59			8.94
Total retail revenue per KWh	9.99			9.68			9.04
Wholesale revenue per KWh	5.77			5.11			4.72

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Energy Source Statistics

	Year Ended Dec. 31
	2014			2013			2012
	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	18,274	53	%	19,647	56	%	21,367	59	%
Natural Gas	8,601	25		7,565	22		7,930	22
Wind (a)	6,472	19		6,750	19		5,752	16
Hydroelectric	617	2		655	2		590	2
Other (b)	294	1		250	1		263	1
Total	34,258	100	%	34,867	100	%	35,902	100	%
Owned generation	23,023	67	%	22,873	66	%	23,766	66	%
Purchased generation	11,235	33		11,994	34		12,136	34
Total	34,258	100	%	34,867	100	%	35,902	100	%

^(a) This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  PSCo uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

^(b) Distributed generation from the Solar*Rewards program is not included, and was approximately 197, 172, and 133 net million KWh for 2014, 2013, and 2012, respectively.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of PSCo are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and commercial and industrial (C&I) customer, as a result of improved building construction technologies, higher appliance efficiencies, and conservation. From 2000 to 2014, average annual sales to the typical PSCo residential customer declined 12 percent, while sales to the typical C&I customer declined 11 percent, each on a weather‑normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act— The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure if records are inadequate. This process could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations including: requiring use of automatic or remote-controlled shut-off valves; requiring testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $2 million per day for related violations. While PSCo cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.  PSCo can generally recover costs to comply with the transmission and distribution integrity management programs through the PSIA rider.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction— PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction under the Federal Natural Gas Act.  PSCo is subject to the DOT and the CPUC with regards to pipeline safety compliance.

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Purchased Natural Gas and Conservation Cost-Recovery Mechanisms— PSCo has retail adjustment clauses that recover purchased natural gas and other resource costs:

• GCA — The GCA recovers the actual costs of purchased natural gas and transportation to meet the requirements of its customers and is revised quarterly to allow for changes in natural gas rates.

• DSMCA — The DSMCA recovers costs of DSM and performance initiatives to achieve various energy savings goals.

• PSIA — The PSIA recovers costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. The rider was extended through 2015.

QSP Requirements — The CPUC established a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service. The CPUC has extended the terms of the QSP through 2015.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation to be 1,983,672 MMBtu. In addition, firm transportation customers hold 771,112 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,754,784 MMBtu per day. The maximum daily deliveries for PSCo for firm and interruptible services were 2,116,747 MMBtu on Dec. 30, 2014 and 1,865,207 MMBtu on Dec. 5, 2013.

PSCo purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 1,814,265 MMBtu per day, which includes 850,840 MMBtu of natural gas held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide approximately 41,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo’s city gate meter stations.

PSCo is required by CPUC regulations to file a natural gas purchase plan each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the 12-month period of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the previous 12-month period.

Natural Gas Supply and Costs

PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates.  In addition, PSCo conducts natural gas price hedging activities that have been approved by the CPUC.

The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by PSCo’s regulated retail natural gas distribution business:

2014	$	4.91
2013	4.20
2012	4.28

The higher cost of natural gas was primarily due to higher market prices from increased demand because of cold weather in early 2014.

PSCo has natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2014, PSCo was committed to approximately $1.4 billion in such obligations under these contracts, which expire in various years from 2015 through 2029.

PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2014, PSCo purchased natural gas from approximately 34 suppliers.

See Items 1A and 7 for further discussion of natural gas supply and costs.

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Natural Gas Operating Statistics

	Year Ended Dec. 31
	2014		2013		2012
Natural gas deliveries (Thousands of MMBtu)
Residential	99,127		100,329		85,280
Commercial and industrial	40,438		40,259		34,597
Total retail	139,565		140,588		119,877
Transportation and other	108,006		109,637		101,490
Total deliveries	247,571		250,225		221,367
Number of customers at end of period
Residential	1,240,674		1,228,917		1,217,972
Commercial and industrial	100,238		100,071		100,110
Total retail	1,340,912		1,328,988		1,318,082
Transportation and other	6,547		6,273		5,746
Total customers	1,347,459		1,335,261		1,323,828
Natural gas revenues (Thousands of Dollars)
Residential	$	824,633	$	729,304	$	650,107
Commercial and industrial	313,821		273,032		241,777
Total retail	1,138,454		1,002,336		891,884
Transportation and other	76,870		78,367		70,551
Total natural gas revenues	$	1,215,324	$	1,080,703	$	962,435
MMBtu sales per retail customer	104.08		105.79		90.95
Revenue per retail customer	$	849	$	754	$	677
Residential revenue per MMBtu	8.32		7.27		7.62
Commercial and industrial revenue per MMBtu	7.76		6.78		6.99
Transportation and other revenue per MMBtu	0.71		0.71		0.70

GENERAL

Seasonality

The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, PSCo’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. See Item 7 for further discussion.

Competition

PSCo is a vertically integrated utility, subject to traditional cost-of-service regulation. However, PSCo is subject to different public policies that promote competition and the development of energy markets. PSCo’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with on-site solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Finally, customers can elect to subscribe to a community solar garden at pricing that affords them the same opportunity to avoid fixed charges as if they had rooftop installations.

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The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, PSCo and its wholesale customers can purchase generation resources from competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. State public utilities commissions, including the CPUC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition, FERC Order 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. PSCo also has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew a franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. Several states, including Colorado, have policies designed to promote the development of solar and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to Xcel Energy’s electric service business. While facing these challenges, PSCo believes its rates and services are competitive with currently available alternatives.

ENVIRONMENTAL MATTERS

PSCo’s facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. PSCo’s facilities have been designed and constructed to operate in compliance with applicable environmental standards. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon PSCo’s operations. See Notes 11 and 12 to the consolidated financial statements for further discussion.

There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. PSCo has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If these future environmental regulations do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. We believe, based on prior state commission practice, we would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2014, PSCo had 2,690 full-time employees and two part-time employees, of which 2,063 were covered under collective-bargaining agreements. See Note 8 to the consolidated financial statements for further discussion.

Item 1A — Risk Factors

Like other companies in our industry, Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Important risks that may adversely affect the business, financial condition, and results of operations are further described below. These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.

Oversight of Risk and Related Processes

A key accountability of the Board of Directors is to identify, manage and mitigate material risk. Our Board employs an effective process for doing so, combining management and Board risk oversight. The guidelines on corporate governance and Board committee charters define the scope of review and inquiry for the Board and its committees regarding risk management. As provided below, management and each committee has responsibility for overseeing aspects of risk management and mitigation of the risk.

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Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability, broadly considering our business, the utility industry, the domestic and global economy and the environment. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. At the same time, the business planning process identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.

At a threshold level, we have developed a robust compliance program and promote a culture of compliance, including tone at the top, which mitigates risk. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management to mitigate the risks inherent in the implementation strategy. Building on this culture of compliance, we manage and further mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of internal corporate areas such as internal audit, the corporate controller and legal services.

Management communicates regularly with the Board and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board in presentations and communications over the course of the year.

The Board has assigned several important aspects of its governance and oversight to four standing committees to ensure issues and risks are well understood and effectively managed. While the Board as a whole reviews management’s key risk assessment and analyzes areas of potential future risk to Xcel Energy, the committees provide focused oversight of specific risks assigned to them. This provides robust and comprehensive risk management that is critical to successful execution of corporate strategy.

Risks Associated with Our Business

Environmental Risks

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources), licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance no longer makes operation of the units economic. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We may be required to pay all or a portion of the cost to remediate (i.e., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2014, these sites included:

• Sites of former MGPs operated by us, our predecessors, or other entities; and

• Third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings.  Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial position or cash flows.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations seeking to protect the environment may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO₂, CO₂ and other GHGs, particulates and cooling water intake systems.  We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

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We are subject to physical and financial risks associated with climate change.

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk. Physical risks from climate change include changes in weather conditions, changes in precipitation and extreme weather events.

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand may raise electricity prices, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur.  To the extent the frequency of extreme weather events increases, this could increase our cost of providing service.  Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units.  A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy.  We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as a tax on GHGs, regulation of CO₂ emissions under section 111(d) of the CAA, or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods.  To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Financial Risks

Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies.  The CPUC regulates many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers.  The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.

The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations.  We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and based on an analysis of our costs incurred in a test year.  Thus, the rates we are allowed to charge may or may not match our costs at any given time.  While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.  Cost disallowances may arise as a result of prudence investigations (e.g., the recent investigation of our PSIA costs). Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.  Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, adverse regulatory rulings or the imposition of additional regulations, including additional environmental or climate change regulation, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

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Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency.  In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.  Any downgrade could lead to higher borrowing costs.  Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment in property, plant and equipment. As a result, we frequently need to access the debt and equity capital markets.  Any disruption in capital markets could have a material impact on our ability to fund our operations.  Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy.  Capital market disruption events and resulting broad financial market distress could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our operating results.  Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense.  Retail credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.

Credit risk also includes the risk that various counterparties that owe us money or product will breach their obligations.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements.  In that event, our financial results could be adversely affected and we could incur losses.

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity. However, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant.  The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception. In addition, the CFTC’s rules permit us to deal in utility operations-related swaps with utility special entities and not be required to register as a swap dealer provided that our aggregate gross notional amount of swap dealing activity (including utility operations-related swaps) does not exceed the general de minimis threshold and provided that we have not exceeded the special entity de minimis threshold (excluding utility operations-related swaps) of $25 million for the preceding 12 months. Our current level of financial swap activity with special entities is significantly below this special entity de minimis threshold; therefore, we will not be classified as a swap dealer in our special entity activity.  Swap transactions with non-special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act.  We are currently reporting all of our swap transactions as part of the Dodd-Frank Act.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties.  We may also have some indirect credit exposure due to participation in organized markets, such as SPP, PJM and MISO, in which any credit losses are socialized to all market participants.

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We do have additional indirect credit exposures to various domestic and foreign financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts.  If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long-term purchased power contracts, the supplier would need to replace that security with an acceptable substitute.  If the security were not replaced, the party could be in technical default under the contract, which would enable us to exercise our contractual rights.

Increasing costs associated with our defined benefit retirement plans and other employee benefits may adverselyaffect our results of operations, financial position or liquidity.

We have defined benefit pension and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations.  In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans with modifications to these funding requirements that allowed additional flexibility in the timing of contributions.  Therefore, our funding requirements and related contributions may change in the future.  Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company could trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

Increasing costs associated with health care plans may adversely affect our results of operations.

Our self-insured costs of health care benefits for eligible employees have increased in recent years.  Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position, and liquidity.  We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise.  Changes in industry standards utilized by management in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.

Operational Risks

We are subject to commodity risks and other risks associated with energy markets and energy production.

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. As a result we are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting).  Actual settlements can vary significantly from estimated fair values recorded to the consolidated financial statements, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.

If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our customers at previously authorized or anticipated costs.  Any such disruption, if significant, would cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers.  The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation including rail shipments of coal, electric generation capacity, transmission, natural gas pipeline capacity, etc.

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Our utility operations are subject to long-term planning risks.

Our utility operations file long-term resource plans with our regulators.  These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage, economic activity, costs, regulatory mechanisms, impact of technology, the installation of distributed generation, customer behavioral response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide.  The addition of customer-site solar installations introduces additional downward pressure on load growth. This could lead to under recovery of costs and excess resources to meet customer demand. PSCo’s aging infrastructure may pose a risk to system reliability and expose us to premature financial obligations. PSCo is engaged in significant and ongoing infrastructure investment programs.

In addition, large industrial customers may leave our system and invest in their own on-site distributed generation or seek law changes to give them the authority to purchase directly from other suppliers or organized markets.  The recent low natural gas price environment has caused some customers to consider their options in this area, particularly customers with industrial processes using steam.  Wholesale customers may purchase directly from other suppliers and procure only transmission service from us.  These circumstances provide for greater long-term planning uncertainty related to future load growth.  Similarly, distributed solar generation may become an economic competitive threat to our load growth in the future. However, we believe the economics, absent significant subsidies, do not support such a trend in the near term unless a state mandates the purchase of such generation. Some states have considered such legislation.

Our natural gas transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.

Our natural gas transmission and distribution activities include a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  We maintain insurance against some, but not all, of these risks and losses.

The occurrence of any of these events not fully covered by insurance could have a material effect on our financial position and results of operations. For our natural gas transmission or distribution lines located near populated areas the level of potential damages resulting from these risks is greater.

Additionally, the operating or other costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires verification of pipeline infrastructure records by intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures.  If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2014, Xcel Energy Inc. and its utility subsidiaries had approximately $11.5 billion of long-term debt and $1.3 billion of short-term debt and current maturities.  Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

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Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2014, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $13.9 million and $0.2 million of exposure. Xcel Energy also had additional guarantees of $31.4 million at Dec. 31, 2014 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time.  If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We are a wholly owned subsidiary of Xcel Energy Inc.  Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc.  Our Board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy Inc.  In 2014, 2013 and 2012 we paid $433.8 million, $263.9 million and $267.0 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs.  This could adversely affect our liquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations.

Public Policy Risks

We may be subject to legislative and regulatory responses to climate change and emissions, with which compliance could be difficult and costly.

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities may be subject to additional regulation under climate change laws at either the state or federal level in the future. The EPA is regulating GHGs under the CAA. The EPA has regulated GHG emissions from motor vehicles and has proposed regulations to reduce GHG emissions from existing power plants that are expected to become final in 2015, with state plans to achieve the EPA’s goals due by 2017. Such regulations could impose substantial costs on our system. The EPA has also proposed regulations that would establish NSPS for any new fossil fuel-fired power plants that may be built which may be adopted in 2015. If adopted, these regulations could significantly increase the cost of building new generating plants.

The United States continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change (UNFCCC). In 2014, the United States and China jointly announced GHG emissions goals. Further, the 20^th Conference of the Parties (COP) to the UNFCCC concluded with the objective of developing an agreement among countries on emission reductions at the 2015 COP. This could result in additional GHG regulation or reduction goals in the United States.

We have been, and in the future may be subject to climate change lawsuits. An adverse outcome in any of these cases could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows and financial condition if such costs are not recovered through regulated rates.

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There are many uncertainties regarding when and in what form climate change legislation or regulations will be imposed. The impact of legislation and regulations will depend on a number of factors, including what GHG emission reduction goals are set, what flexibility is allowed to meet the goals, how and whether early action to reduce GHG emissions is credited, whether GHG sources in other sectors of the economy are regulated, the degree to which GHG offsets are recognized as compliance options, how any emission allowances would be allocated to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. In addition, international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements in a timely manner. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include rules associated with emissions of SO₂ and NOx, mercury, regional haze, ozone and particulate matter, water discharges and ash management. The costs of investment to comply with these rules could be substantial and in some cases would lead to early retirement of coal units.. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders.  The FERC can now impose penalties of up to $1 million per violation per day.  In addition, NERC electric reliability standards are now mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations.  If a serious reliability incident did occur, it could have a material effect on our operations or financial results. Some states have the authority to impose substantial penalties in the event of non-compliance.

We attempt to mitigate the risk of regulatory penalties through formal training on such prohibited practices and a compliance function that reviews our interaction with the markets under FERC and CFTC jurisdictions.  However, there is no guarantee our compliance program will be sufficient to ensure against violations.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions both positively and negatively. Growth in our customer base is correlated with economic conditions. While the number of customers is growing, sales growth is relatively modest due to an increased focus on energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which are discussed in the capital market risk section above.

Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies.  Additionally, the cost of those commodities may be higher than expected.

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Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business.  We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel.  We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

The insurance industry has also been affected by these events and the availability of insurance may decrease.  In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business.  Because our generation, transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation, or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a neighboring system.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results.

The degree to which we are able to maintain day-to-day operations in response to unforeseen events will in part determine the financial impact of certain events on our financial condition and results.It is difficult to predict the magnitude of such events and associated impacts.

A cyber incident or cyber security breach could have a material effect on our business.

We operate in an industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems (e.g., information about our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States, and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations, or exposing us to liability. Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business.  In addition, such an event would likely receive regulatory scrutiny at both the federal and state level.  We are unable to quantify the potential impact of cyber security threats or subsequent related actions.  These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may causesignificant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

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We maintain security measures designed to protect our information technology systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information.   If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting. We are unable to quantify the potential impact of cyber security incidents on our business.

Rising energy prices could negatively impact our business.

While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered.  In addition, higher fuel costs could reduce customer demand and/or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating.  Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.  Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows.

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.

Electric Utility Generating Stations:
Station, Location and Unit	Fuel	Installed	Summer 2014 Net Dependable Capability (MW)
Steam:
Cherokee-Denver, Colo., 2 Units	Coal	1957-1968	504
Comanche-Pueblo, Colo.
Unit 1	Coal	1973	325
Unit 2	Coal	1975	335
Unit 3	Coal	2010	500	(a)
Craig-Craig, Colo., 2 Units	Coal	1979-1980	83	(b)
Hayden-Hayden, Colo., 2 Units	Coal	1965-1976	237	(c)
Pawnee-Brush, Colo., 1 Unit	Coal	1981	505
Valmont-Boulder, Colo., 1 Unit	Coal	1964	184
Zuni-Denver, Colo., 1 Unit	Coal	1948-1954	59
Combustion Turbine:
Blue Spruce-Aurora, Colo., 2 Units	Natural Gas	2003	264
Fort St. Vrain-Platteville, Colo., 6 Units	Natural Gas	1972-2009	969
Rocky Mountain-Keenesburg, Colo., 3 Units	Natural Gas	2004	580
Various locations, 6 Units	Natural Gas	Various	172
Hydro:
Cabin Creek-Georgetown, Colo.
Pumped Storage, 2 Units	Hydro	1967	210
Various locations, 9 Units	Hydro	Various	26
Wind:
Ponnequin-Weld County, Colo., 37 Units	Wind	1999-2001	25	(d)
		Total	4,978

^(a)  Based on PSCo’s ownership interest of 67 percent of Unit 3.

^(b) Based on PSCo’s ownership interest of 10 percent.

^(c) Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2.

^(d) This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.  Therefore, the on-demand net dependable capacity is zero.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2014:

Conductor Miles
345 KV	2,630
230 KV	12,162
138 KV	92
115 KV	4,889
Less than 115 KV	75,110

PSCo had 229 electric utility transmission and distribution substations at Dec. 31, 2014.

Natural gas utility mains at Dec. 31, 2014:

Miles
Transmission	2,258
Distribution	21,844

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Item 3 — 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 12 to the consolidated financial statements for further discussion of legal claims and environmental proceedings.  See Item 1 and Note 11 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

Item 4 — Mine Safety Disclosures

None.

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

PSCo is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. PSCo’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

See Note 4 to the financial statements for further discussion of PSCo’s dividend policy.

The dividends declared during 2014 and 2013 were as follows:

(Thousands of Dollars)	2014		2013
First quarter	$	194,022	$	66,678
Second quarter	96,391		65,461
Third quarter	78,241		65,000
Fourth quarter	83,652		65,134

Item 6 — Selected Financial Data

This is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 7 — 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 I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries.  It is replaced with management’s narrative analysis of the results of operations set forth in general instructions I(2)(a) of Form 10-K 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 consolidated financial statements and related notes to the consolidated financial statements.

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of slowdown in the U.S. economy or delay in growth recovery; actions of credit rating agencies; trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; 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; availability or cost of capital; employee work force factors; and the other risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations

PSCo’s net income was approximately $455.2 million for 2014, compared with approximately $453.4 million for 2013.  The increase is mainly due to higher natural gas and electric margins primarily due to rate increases, higher AFUDC, lower O&M expenses and weather-normalized sales growth. These factors were partially offset by higher property taxes, depreciation, accruals associated with the electric earnings test refund obligations and the unfavorable impact of weather.

Electric Revenues and Margin

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

(Millions of Dollars)	2014			2013
Electric revenues	$	3,126		$	3,081
Electric fuel and purchased power	(1,405		)	(1,336		)
Electric margin	$	1,721		$	1,745

The following tables summarize the components of the changes in electric revenues and electric margin for the year ended Dec. 31:

Electric Revenues

(Millions of Dollars)	2014 vs. 2013
Fuel and purchased power cost recovery	$	84
Non-fuel riders	9
Transmission revenue	8
Retail sales growth, excluding weather impact	7
Estimated impact of weather	(30		)
Trading, including REC sales	(23		)
Retail rate increase (net of estimated earnings test refund obligations)	(13		)
Other, net	3
Total increase in electric revenues	$	45

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Electric Margin

(Millions of Dollars)	2014 vs. 2013
Estimated impact of weather	$	(30	)
Retail rate increase (net of estimated earnings test refund obligations)	(13		)
Trading, including REC sales	(8		)
Non-fuel riders	9
Transmission revenue, net of costs	8
Retail sales growth, excluding weather impact	7
Other, net	3
Total decrease in electric margin	$	(24	)

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases.  However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.  The following table details natural gas revenues and margin:

(Millions of Dollars)	2014			2013
Natural gas revenues	$	1,215		$	1,081
Cost of natural gas sold and transported	(726		)	(621		)
Natural gas margin	$	489		$	460

The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the year ended Dec. 31:

Natural Gas Revenues

(Millions of Dollars)	2014 vs. 2013
Purchased natural gas adjustment clause recovery	$	106
Retail rate increase	19
PSIA rider (offset by expense)	14
Retail sales growth, excluding weather impact	7
Estimated impact of weather	(7		)
Other, net	(5		)
Total increase in natural gas revenues	$	134

Natural Gas Margin

(Millions of Dollars)	2014 vs. 2013
Retail rate increase	$	19
PSIA rider (offset by expenses)	14
Retail sales growth, excluding weather impact	7
Estimated impact of weather	(7		)
Other, net	(4		)
Total increase in natural gas margin	$	29

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Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses decreased by $10.5 million, or 1.4 percent, for 2014 compared with the same period in 2013.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2014 vs. 2013
Employee benefits	$	(12	)
Plant generation costs	(2		)
Other, net	3
Total decrease in O&M expenses	$	(11	)

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

DSM Program Expenses— DSM program expenses increased $0.4 million, or 0.3 percent, for 2014 compared with 2013.  The higher expense is primarily attributable to an increase in the electric rate used to recover program expenses.  DSM program expenses are recovered concurrently through riders and base rates.

Depreciation and Amortization— Depreciation and amortization expense increased by approximately $18.8 million, or 5.2 percent, for 2014 compared with 2013.  The increase is primarily attributable to normal system expansion.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased by $24.1 million, or 17.5 percent, for 2014 compared with 2013. The increase is primarily due to higher property taxes.

AFUDC— AFUDC increased by $18.2 million for 2014 compared with 2013.  The increase is primarily due to construction related to the CACJA.

Interest Charges —Interest charges decreased by $1.7 million, or 1.0 percent, for 2014 compared with 2013.  The decrease is primarily due to refinancings at lower interest rates, partially offset by higher long-term debt levels.

Income Taxes — Income tax expense decreased $7.1 million for 2014 compared with 2013.  The decrease in income tax expense was primarily due to lower pretax earnings in 2014 and increased permanent plant-related adjustments in 2014  The ETR was 34.9 percent2014 compared with 35.6 percent for 2013 due to these adjustments.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

PSCo is exposed to a variety of market risks in the normal course of business.  Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity.  All financial and commodity-related instruments, including derivatives, are subject to market risk.  See Note 10 to the consolidated financial statements for further discussion of market risks associated with derivatives.

PSCo is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives.  In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral.  While PSCo expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose PSCo to some credit and nonperformance risk.

Though no material non-performance risk currently exists with the counterparties to PSCo’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties.  Distress in the financial markets may also impact the fair value of the securities in the master pension trust, as well as PSCo’s ability to earn a return on short-term investments of excess cash.

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Commodity Price Risk — PSCo is exposed to commodity price risk in its electric and natural gas operations.  Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities.  Commodity price risk is also managed through the use of financial derivative instruments.  PSCo’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.

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 the policy.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the years ended Dec. 31, were as follows:

(Thousands of Dollars)	2014			2013
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	318		$	792
Contracts realized or settled during the period	(500		)	4,986
Commodity trading contract additions and changes during the period	182			(5,460		)
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	—		$	318

At Dec. 31, 2014, there were no net commodity trading contract assets outstanding. At Dec. 31, 2013, a 10 percent increase or decrease in market prices for commodity trading contracts would have an immaterial impact on pretax income from continuing operations.

PSCo’s wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, including transactions that are not recorded at fair value, using an industry standard methodology known as Value at Risk (VaR).  VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.  The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:

(Millions of Dollars)	Year Ended Dec. 31		VaR Limit		Average		High		Low
2013	$	0.29	$	3.00	$	0.41	$	1.65	$	< 0.01

Interest Rate Risk — PSCo is subject to the risk of fluctuating interest rates in the normal course of business.  PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

At Dec. 31, 2014, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately $3.8 million, and at Dec. 31, 2013 a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would have no impact on pretax interest expense. See Note 10 to the consolidated financial statements for a discussion of PSCo’s interest rate derivatives.

Credit Risk — PSCo is also exposed to credit risk.  Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations.  PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

At Dec. 31, 2014, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $13.6 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $4.1 million.  At Dec. 31, 2013, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $9.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $1.4 million.

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PSCo conducts standard credit reviews for all counterparties.  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.  Distress in the financial markets could increase PSCo’s credit risk.

Fair Value Measurements

PSCo follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements.  See Note 10 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2014.  PSCo also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities.  The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2014.

Commodity derivative assets and liabilities assigned to Level 3 typically consist of forwards and options that are long-term in nature. Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers.  When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3.  There were no Level 3 commodity derivative assets or liabilities at Dec. 31, 2014.

Item 8 — Financial Statements and Supplementary Data

See Item 15-1 in Part IV for an index of financial statements included herein.

See Note 17 to the consolidated financial statements for summarized quarterly financial data.

31

Management Report on Internal Controls Over Financial Reporting

The management of PSCo is responsible for establishing and maintaining adequate internal control over financial reporting. PSCo’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and PSCo’s management and board of directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2014. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2014, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ BEN FOWKE	/s/ TERESA S. MADDEN
Ben Fowke	Teresa S. Madden
Chairman and Chief Executive Officer	Executive Vice President, Chief Financial Officer
Feb. 20, 2015	Feb. 20, 2015

32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Public Service Company of Colorado

We have audited the accompanying consolidated balance sheets and statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, cash flows, and common stockholder’s equity for each of the three years in the period ended December 31, 2014.  Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 20, 2015

33

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2014			2013			2012
Operating revenues
Electric	$	3,125,937		$	3,081,171		$	2,969,899
Natural gas	1,215,324			1,080,703			962,435
Steam and other	41,888			40,754			36,959
Total operating revenues	4,383,149			4,202,628			3,969,293
Operating expenses
Electric fuel and purchased power	1,405,498			1,335,818			1,235,343
Cost of natural gas sold and transported	725,754			621,120			532,417
Cost of sales — steam and other	16,831			17,039			15,438
Operating and maintenance expenses	751,786			762,322			742,975
Demand side management program expenses	139,780			139,337			123,205
Depreciation and amortization	379,202			360,417			338,827
Taxes (other than income taxes)	161,928			137,816			131,869
Total operating expenses	3,580,779			3,373,869			3,120,074
Operating income	802,370			828,759			849,219
Other income, net	4,265			3,136			4,736
Allowance for funds used during construction —  equity	46,784			33,173			16,354
Interest charges and financing costs
Interest charges — includes other financing costs of $6,340, $6,866, and $7,088, respectively	171,881			173,602			188,094
Allowance for funds used during construction — debt	(17,241		)	(12,657		)	(8,405		)
Total interest charges and financing costs	154,640			160,945			179,689
Income before income taxes	698,779			704,123			690,620
Income taxes	243,591			250,740			232,544
Net income	$	455,188		$	453,383		$	458,076

See Notes to Consolidated Financial Statements

34

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2014			2013			2012
Net income	$	455,188		$	453,383		$	458,076
Other comprehensive loss
Derivative instruments:
Net fair value (decrease) increase, net of tax of $(43), $5 and $(5,708), respectively	(72		)	9			(9,311		)
Reclassification of gains to net income, net of tax of $(287), $(294) and $(725), respectively	(468		)	(476		)	(1,183		)
Other comprehensive loss	(540		)	(467		)	(10,494		)
Comprehensive income	$	454,648		$	452,916		$	447,582

See Notes to Consolidated Financial Statements

35

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2014			2013			2012
Operating activities
Net income	$	455,188		$	453,383		$	458,076
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	383,992			365,713			344,226
Demand side management program amortization	4,331			4,802			5,299
Deferred income taxes	227,823			316,253			38,092
Amortization of investment tax credits	(2,941		)	(2,935		)	(2,957		)
Allowance for equity funds used during construction	(46,784		)	(33,173		)	(16,354		)
Provision for bad debts	17,005			16,784			16,323
SmartGridCity	—			—			10,666
Net realized and unrealized hedging and derivative transactions	(2,578		)	(3,571		)	(39,338		)
Changes in operating assets and liabilities:
Accounts receivable	(42,921		)	5,089			(58,226		)
Accrued unbilled revenues	(23,132		)	14,707			18,920
Inventories	(972		)	(14,857		)	30,203
Prepayments and other	(81,715		)	(7,210		)	(3,466		)
Accounts payable	(22,789		)	59,361			(56,176		)
Net regulatory assets and liabilities	130,499			108,400			(31,776		)
Other current liabilities	5,284			16,561			34,305
Pension and other employee benefit obligations	(38,905		)	(48,886		)	(57,974		)
Change in other noncurrent assets	5,537			3,862			(10,101		)
Change in other noncurrent liabilities	(19,130		)	17,191			(1,267		)
Net cash provided by operating activities	947,792			1,271,474			678,475
Investing activities
Utility capital/construction expenditures	(1,114,338		)	(1,066,700		)	(873,383		)
Allowance for equity funds used during construction	46,784			33,173			16,354
Investments in utility money pool arrangement	(603,000		)	(1,495,000		)	(1,000,000		)
Repayments from utility money pool arrangement	659,000			1,423,000			1,052,000
Net cash used in investing activities	(1,011,554		)	(1,105,527		)	(805,029		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	382,000			(154,000		)	154,000
Borrowings under utility money pool arrangement	333,000			14,000			36,000
Repayments under utility money pool arrangement	(333,000		)	(14,000		)	(36,000		)
Proceeds from issuance of long-term debt	295,598			492,313			790,379
Repayments of long-term debt	(275,000		)	(250,000		)	(648,750		)
Capital contributions from parent	81,498			25,621			99,283
Dividends paid to parent	(433,788		)	(263,942		)	(266,971		)
Net cash provided by (used in) financing activities	50,308			(150,008		)	127,941
Net change in cash and cash equivalents	(13,454		)	15,939			1,387
Cash and cash equivalents at beginning of period	21,089			5,150			3,763
Cash and cash equivalents at end of period	$	7,635		$	21,089		$	5,150
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(150,011	)	$	(155,457	)	$	(179,610	)
Cash (paid) received for income taxes, net	(91,810		)	34,946			(179,321		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	139,616		$	142,103		$	94,288

See Notes to Consolidated Financial Statements

36

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	Dec. 31
	2014			2013
Assets
Current assets
Cash and cash equivalents	$	7,635		$	21,089
Accounts receivable, net	322,885			328,675
Accounts receivable from affiliates	50,842			19,136
Investments in utility money pool arrangement	16,000			72,000
Accrued unbilled revenues	294,049			270,917
Inventories	238,979			238,007
Regulatory assets	120,120			150,163
Deferred income taxes	64,587			87,267
Derivative instruments	1,731			6,576
Prepaid taxes	90,365			9,439
Prepayments and other	23,979			23,190
Total current assets	1,231,172			1,226,459
Property, plant and equipment, net	11,626,956			10,742,397
Other assets
Regulatory assets	903,973			826,037
Derivative instruments	5,176			6,905
Other	48,506			52,520
Total other assets	957,655			885,462
Total assets	$	13,815,783		$	12,854,318
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	8,178		$	282,143
Short-term debt	382,000			—
Accounts payable	425,133			451,243
Accounts payable to affiliates	46,736			45,902
Regulatory liabilities	134,459			79,499
Taxes accrued	159,470			154,194
Accrued interest	48,409			48,492
Dividends payable to parent	83,652			65,134
Derivative instruments	5,774			6,734
Other	72,002			89,571
Total current liabilities	1,365,813			1,222,912
Deferred credits and other liabilities
Deferred income taxes	2,437,641			2,206,179
Deferred investment tax credits	36,273			39,230
Regulatory liabilities	464,421			424,690
Asset retirement obligations	225,296			60,398
Derivative instruments	18,257			23,366
Customer advances	229,990			251,062
Pension and employee benefit obligations	202,031			167,127
Other	68,171			66,855
Total deferred credits and other liabilities	3,682,080			3,238,907
Commitments and contingencies
Capitalization
Long-term debt	3,882,051			3,590,500
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2014 and 2013, respectively	—			—
Additional paid in capital	3,522,788			3,441,290
Retained earnings	1,386,929			1,384,047
Accumulated other comprehensive loss	(23,878		)	(23,338		)
Total common stockholder’s equity	4,885,839			4,801,999
Total liabilities and equity	$	13,815,783		$	12,854,318

See Notes to Consolidated Financial Statements

37

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

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

	Common Stock Issued								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2011	100	$	—	$	3,316,386	$	1,001,709		$	(12,377	)	$	4,305,718
Net income						458,076						458,076
Other comprehensive loss									(10,494		)	(10,494		)
Common dividends declared to parent						(266,848		)				(266,848		)
Contribution of capital by parent				99,283								99,283
Balance at Dec. 31, 2012	100	$	—	$	3,415,669	$	1,192,937		$	(22,871	)	$	4,585,735
Net income						453,383						453,383
Other comprehensive loss									(467		)	(467		)
Common dividends declared to parent						(262,273		)				(262,273		)
Contribution of capital by parent				25,621								25,621
Balance at Dec. 31, 2013	100	$	—	$	3,441,290	$	1,384,047		$	(23,338	)	$	4,801,999
Net income						455,188						455,188
Other comprehensive loss									(540		)	(540		)
Common dividends declared to parent						(452,306		)				(452,306		)
Contribution of capital by parent				81,498								81,498
Balance at Dec. 31, 2014	100	$	—	$	3,522,788	$	1,386,929		$	(23,878	)	$	4,885,839

See Notes to Consolidated Financial Statements

38

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

	Dec. 31
	2014			2013
Long-Term Debt
First Mortgage Bonds, Series due:
April 1, 2014, 5.5%	$	—		$	275,000
Sept. 1, 2017, 4.375% (a)	129,500			129,500
Aug. 1, 2018, 5.8%	300,000			300,000
June 1, 2019, 5.125%	400,000			400,000
Nov. 15, 2020, 3.2%	400,000			400,000
Sept. 15, 2022, 2.25%	300,000			300,000
March 15, 2023, 2.5%	250,000			250,000
Sept. 1, 2037, 6.25%	350,000			350,000
Aug. 1, 2038, 6.5%	300,000			300,000
Aug. 15, 2041, 4.75%	250,000			250,000
Sept. 15, 2042, 3.6%	500,000			500,000
March 15, 2043, 3.95%	250,000			250,000
March 15, 2044, 4.3%	300,000			—
Capital lease obligations, through 2060, 11.2% — 14.3%	172,209			179,444
Unamortized discount	(11,480		)	(11,301		)
Total	3,890,229			3,872,643
Less current maturities	8,178			282,143
Total long-term debt	$	3,882,051		$	3,590,500
Common Stockholder’s Equity
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2014 and 2013, respectively.	$	—		$	—
Additional paid-in capital	3,522,788			3,441,290
Retained earnings	1,386,929			1,384,047
Accumulated other comprehensive loss	(23,878		)	(23,338		)
Total common stockholder’s equity	$	4,885,839		$	4,801,999

^(a)  Pollution control financing.

See Notes to Consolidated Financial Statements

39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts— PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  PSCo’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation— PSCo’s consolidated financial statements include its wholly-owned subsidiaries.  In the consolidation process, all intercompany transactions and balances are eliminated.  PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities.  PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.  See Note 6 for further discussion of jointly owned generation, transmission, and gas facilities and related ownership percentages.

PSCo evaluates its arrangements and contracts with other entities, including but not limited to, investments, PPAs and fuel contracts to determine if the other party is a variable interest entity, if PSCo has a variable interest and if PSCo is the primary beneficiary.  PSCo follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether PSCo is a variable interest entity’s primary beneficiary.  See Note 12 for further discussion of variable interest entities.

Use of Estimates— In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available.  Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs.  The recorded estimates are revised when better information becomes available or when actual amounts can be determined.  Those revisions can affect operating results.

Regulatory Accounting— PSCo accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

• Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on PSCo’s financial condition, results of operations and cash flows.  See Note 13 for further discussion of regulatory assets and liabilities.

Revenue Recognition— Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.  PSCo presents its revenue net of any excise or other fiduciary-type taxes or fees.

40

PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems.  These programs include approximately sixteen unique DSM products for commercial and industrial customers, as well as approximately one dozen DSM products for residential customers. Each DSM product may include one or up to several hundred measures that qualify for rebates and/or incentives.

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms.  The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals.  PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Property, Plant and Equipment and Depreciation— Property, plant and equipment is stated at original cost.  The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC.  The cost of plant retired is charged to accumulated depreciation and amortization.  Amounts recovered in rates for future removal costs are recorded as regulatory liabilities.  Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

PSCo records depreciation expense related to its plant using the straight-line method over the plant’s useful life.  Actuarial life studies are performed and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.7, 2.8 and 2.6 percent for the years ended Dec. 31, 2014, 2013 and 2012, respectively.

Leases — PSCo evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 12 for further discussion of leases.

AFUDC— AFUDC represents the cost of capital used to finance utility construction activity.  AFUDC is computed by applying a composite financing rate to qualified CWIP.  The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital).  AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates.

41

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases, including certain generation and transmission projects, the CPUC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.  In other cases, the CPUC has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.

AROs— PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. PSCo also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 12 for further discussion of AROs.

Income Taxes— PSCo accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements.  PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.  In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property.  Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.

PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  PSCo recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.  Recognition of changes in uncertain tax positions are reflected as a component of income tax.

PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as combined or separate state income tax returns.  Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings.  Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 7 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments— PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, and commodity trading activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

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Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.  PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customer, see Note 10.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge).  Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

PSCo evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

See Note 10 for further discussion of PSCo’s risk management and derivative activities.

Commodity Trading Operations— All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.  See Note 10 for further discussion.

Fair Value Measurements— PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value.  See Note 10 for further discussion.

Cash and Cash Equivalents— PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts— Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

Inventory— All inventory is recorded at average cost.

RECs — RECs aremarketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources.  RECs are awarded upon delivery of the associated energy and can be bought and sold.  RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced.  PSCo acquires RECs from the generation or purchase of renewable power.

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost.  The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.  As a result of state regulatory orders, PSCo records that cost as a regulatory asset when the amount is recoverable in future rates.

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Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.  The sales of RECs for trading purposes are recorded in electric utility operating revenues, net of the cost of the RECs, transaction costs, and amounts credited to customers under margin-sharing mechanisms.

Emission Allowances — Emission allowances, including the annual SO₂ and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees.  PSCo follows the inventory accounting model for all emission allowances.  Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

Environmental Costs— Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the liability can be reasonably estimated.  Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed.  If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 12 for further discussion of environmental costs.

Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 8 for further discussion of benefit plans and other postretirement benefits.

Guarantees — PSCo recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2014 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2. Accounting Pronouncements

Recently Issued

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

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3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	346,007		$	351,180
Less allowance for bad debts	(23,122		)	(22,505		)
	$	322,885		$	328,675

(Thousands of Dollars)	Dec. 31, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	55,491	$	53,127
Fuel	80,963		86,062
Natural gas	102,525		98,818
	$	238,979	$	238,007

(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	10,927,867		$	10,177,056
Natural gas plant	3,210,242			2,757,605
Common and other property	827,708			762,916
Plant to be retired (a)	71,534			101,279
Construction work in progress	828,620			952,469
Total property, plant and equipment	15,865,971			14,751,325
Less accumulated depreciation	(4,239,015		)	(4,008,928		)
	$	11,626,956		$	10,742,397

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

4. 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 Dec. 31, 2014
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	1
Maximum amount outstanding	21
Weighted average interest rate, computed on a daily basis	0.28		%
Weighted average interest rate at period end	N/A

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(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	4.2			0.1			0.3
Maximum amount outstanding	97			12			8
Weighted average interest rate, computed on a daily basis	0.25		%	0.36		%	0.33		%
Weighted average interest rate at period end	N/A			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 borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2014
Borrowing limit	$	700
Amount outstanding at period end	382
Average amount outstanding	292
Maximum amount outstanding	393
Weighted average interest rate, computed on a daily basis	0.37		%
Weighted average interest rate at period end	0.65

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	382			—			154
Average amount outstanding	167			38			8
Maximum amount outstanding	393			332			165
Weighted average interest rate, computed on a daily basis	0.31		%	0.34		%	0.33		%
Weighted average interest rate at period end	0.65			N/A			0.35

Letters of Credit— PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 2014 and 2013, there was $6.4 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 credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Amended Credit Agreement —In October 2014, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an extension of maturity from July 2017 to October 2019. The borrowing limit for PSCo remained at $700 million.

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

Other features of PSCo’s credit facility include:

• PSCo may increase its credit facility by up to $100 million.

• The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. PSCo was in compliance as its debt-to-total capitalization ratio was 47 percent and 45 percent at Dec. 31, 2014 and 2013, respectively. If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

• The credit facility has a cross-default provision that provides PSCo will be in default on its borrowings under the facility if PSCo or any of its subsidiaries whose total assets exceed 15 percent of PSCo’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

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• The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.

• The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.

At Dec. 31, 2014, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	388.4	$	311.6

^(a)  These credit facilities have been amended to extend the maturity to 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 Dec. 31, 2014 and 2013.

Long-Term Borrowings

Generally, all real and personal property of PSCo is subject to the liens of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

In March 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044. In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023, and $250 million of 3.95 percent first mortgage bonds due March 15, 2043.

During the next five years, PSCo has long-term debt maturities of $130 million, $300 million and $400 million due in 2017, 2018 and 2019, respectively.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $26.5 million and $37.0 million, net of amortization, at Dec. 31, 2014 and 2013, respectively.  PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend Restrictions —PSCo’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

5. Preferred Stock

PSCo has authorized the issuance of preferred stock.

Preferred Shares Authorized	Par Value		Preferred Shares Outstanding
10,000,000	$	0.01	None

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6. Joint Ownership of Generation, Transmission and Gas Facilities

Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2014:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	98,145	$	66,333	$	1,405	75.5	%
Hayden Unit 2	121,571		59,999		8,867		37.4
Hayden Common Facilities	37,049		16,928		135		53.1
Craig Units 1 and 2	59,860		35,573		3,013		9.7
Craig Common Facilities 1, 2 and 3	36,890		17,735		527		6.5
Comanche Unit 3	883,971		81,748		64		66.7
Comanche Common Facilities	23,624		1,051		308		82.0
Electric Transmission:
Transmission and other facilities, including substations	151,301		60,847		1,730		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	16,278		5,594		—		60.0
Total	$	1,428,689	$	345,808	$	16,049

PSCo has approximately 820 MW of jointly owned generating capacity.  PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts.  Each of the respective owners is responsible for providing its own financing.

7. Income Taxes

Tax Increase Prevention Act of 2014— In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following:

• The R&E credit was extended for 2014;

• PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and

• 50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.

The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment.

American Taxpayer Relief Act of 2012— In 2013, the American Taxpayer Relief Act (ATRA) was signed into law. The ATRA provided for the following:

• The top tax rate for dividends increased from 15 percent to 20 percent. The 20 percent dividend rate is now consistent with the tax rates for capital gains;

• The R&E credit was extended for 2012 and 2013;

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• PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; and

• 50 percent bonus depreciation was extended one year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation.

The accounting related to the ATRA, including the provisions related to 2012, was recorded beginning in the first quarter of 2013 because a change in tax law is accounted for in the period of enactment.

Prescription drug tax benefit— In the third quarter of 2012, PSCo implemented a tax strategy related to the allocation of funding of PSCo’s retiree prescription drug plan.  This strategy restored a portion of the tax benefit associated with federal subsidies for prescription drug plans that had been accrued since 2004 and was expensed in 2010.  As a result, PSCo recognized approximately $17 million of income tax benefit.

Medicare Part D— In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. PSCo is not expected to accrue any income tax expense related to this adjustment. At Dec. 31, 2014, the IRS has begun the Appeals process; however, the outcome and timing of a resolution is uncertain.

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

Unrecognized Tax Benefits— The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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)	Dec. 31, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.9	$	2.5
Unrecognized tax benefit — Temporary tax positions	10.0		5.9
Total unrecognized tax benefit	$	11.9	$	8.4

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

(Millions of Dollars)	2014			2013			2012
Balance at Jan. 1	$	8.4		$	9.6		$	11.4
Additions based on tax positions related to the current year	3.7			3.9			1.9
Reductions based on tax positions related to the current year	(0.7		)	—			(1.5		)
Additions for tax positions of prior years	2.8			3.3			2.0
Reductions for tax positions of prior years	(1.2		)	(0.9		)	(4.2		)
Settlements with taxing authorities	(1.1		)	(7.5		)	—
Balance at Dec. 31	$	11.9		$	8.4		$	9.6

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

(Millions of Dollars)	Dec. 31, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(3.9	)	$	(7.0	)

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

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2014, 2013 and 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2014, 2013 or 2012.

Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2014		2013
Federal NOL carryforward	$	319.5	$	315.5
Federal tax credit carryforwards	22.3		19.4
State NOL carryforwards	690.1		664.6
State tax credit carryforwards, net of federal detriment	12.2		11.2

The federal carryforward periods expire between 2021 and 2034.  The state carryforward periods expire between 2017 and 2033.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.  The following reconciles such differences for the years ending Dec. 31:

	2014		2013		2012
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	2.8		3.0		2.3
Change in unrecognized tax benefits	(0.1	)	0.1		0.1
Regulatory differences — utility plant items	(2.1	)	(1.4	)	(0.6	)
Tax credits recognized, net of federal income tax expense	(0.8	)	(0.8	)	(0.6	)
Prescription drug tax benefit and Medicare Part D	—		—		(2.5	)
Other, net	0.1		(0.3	)	—
Effective income tax rate	34.9	%	35.6	%	33.7	%

The components of income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2014			2013			2012
Current federal tax (benefit) expense	$	9,550		$	(52,408	)	$	176,354
Current state tax (benefit) expense	2,611			(7,252		)	24,502
Current change in unrecognized tax (benefit) expense	6,548			(2,918		)	(3,447		)
Deferred federal tax expense	208,781			273,916			38,309
Deferred state tax expense (benefit)	26,196			38,243			(4,424		)
Deferred change in unrecognized tax expense (benefit)	(7,154		)	4,094			4,207
Deferred investment tax credits	(2,941		)	(2,935		)	(2,957		)
Total income tax expense	$	243,591		$	250,740		$	232,544

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The components of deferred income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2014			2013			2012
Deferred tax expense excluding items below	$	254,142		$	335,580		$	41,233
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(26,649		)	(19,616		)	(9,574		)
Tax benefit allocated to other comprehensive income and other	330			289			6,433
Deferred tax expense	$	227,823		$	316,253		$	38,092

The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:

(Thousands of Dollars)	2014		2013
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,467,260	$	2,197,685
Employee benefits	110,556		100,003
Other	140,080		132,436
Total deferred tax liabilities	$	2,717,896	$	2,430,124
Deferred tax assets:
NOL carryforward	$	143,158	$	137,043
Unbilled revenue - fuel costs	57,654		49,171
Rate refund	43,735		26,943
Tax credit carryforward	34,493		30,643
Regulatory liabilities	14,549		14,893
Deferred investment tax credits	13,781		14,905
Other	37,472		37,614
Total deferred tax assets	$	344,842	$	311,212
Net deferred tax liability	$	2,373,054	$	2,118,912

8. Benefit Plans and Other Postretirement Benefits

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, PSCo accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. PSCo is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, PSCo accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for PSCo employees.

Xcel Energy, which includes PSCo, offers various benefit plans to its employees. Approximately 77 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2014, PSCo had 2,063 bargaining employees covered under a collective-bargaining agreement, which expired in May 2014. While collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended until the parties reach an agreement or a decision is rendered by an arbitrator.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets 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 included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

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Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents —The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Derivative Instruments —Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Pension Benefits

Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2014 and 2013 were $46.5 million and $36.5 million, respectively, of which $3.8 million and $3.5 million were attributable to PSCo. In 2014 and 2013, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4.7 million and $6.6 million, respectively, of which $0.6 million in each year was attributable to PSCo. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

• Investment returns in 2014 were above the assumed levels of 6.81 percent;

• Investment returns in 2013 were below the assumed level of 6.47 percent;

• Investment returns in 2012 were above the assumed level of 6.65 percent; and

• In 2015, PSCo’s expected investment-return assumption is 6.81 percent.

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The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year:

	2014		2013
Domestic and international equity securities	32	%	29	%
Long-duration fixed income and interest rate swap securities	35		36
Short-to-intermediate term fixed income securities	12		14
Alternative investments	18		19
Cash	3		2
Total	100	%	100	%

The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	82,486	$	—		$	—	$	82,486
Derivatives	—		508			—		508
Government securities	—		180,912			—		180,912
Corporate bonds	—		115,593			—		115,593
Asset-backed securities	—		1,360			—		1,360
Mortgage-backed securities	—		3,997			—		3,997
Common stock	37,067		—			—		37,067
Private equity investments	—		—			50,210		50,210
Commingled funds	—		629,439			—		629,439
Real estate	—		—			18,410		18,410
Securities lending collateral obligation and other	—		(16,117		)	—		(16,117		)
Total	$	119,553	$	915,692		$	68,620	$	1,103,865

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	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	42,721	$	—	$	—	$	42,721
Derivatives	—		14,755		—		14,755
Government securities	—		125,891		—		125,891
Corporate bonds	—		183,078		—		183,078
Asset-backed securities	—		2,356		—		2,356
Mortgage-backed securities	—		5,267		—		5,267
Common stock	34,742		—		—		34,742
Private equity investments	—		—		49,022		49,022
Commingled funds	—		582,722		—		582,722
Real estate	—		—		15,556		15,556
Securities lending collateral obligation and other	—		10,947		—		10,947
Total	$	77,463	$	925,016	$	64,578	$	1,067,057

The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2014, 2013 and 2012:

(Thousands of Dollars)	Jan. 1, 2014		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2014
Private equity investments	$	49,022	$	8,495	$	(4,299	)	$	(3,008	)	$	—	$	50,210
Real estate	15,556		1,180		(302		)	1,976			—		18,410
Total	$	64,578	$	9,675	$	(4,601	)	$	(1,032	)	$	—	$	68,620

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	4,604	$	—		$	—		$	—		$	(4,604	)	$	—
Mortgage-backed securities	12,058		—			—			—			(12,058		)	—
Private equity investments	47,056		7,074			(4,027		)	(1,081		)	—			49,022
Real estate	19,273		(870		)	3,769			3,048			(9,664		)	15,556
Total	$	82,991	$	6,204		$	(258	)	$	1,967		$	(26,326	)	$	64,578

^(a)  Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2012
Asset-backed securities	$	9,824	$	1,175	$	(1,597	)	$	(4,798	)	$	—	$	4,604
Mortgage-backed securities	23,614		550		(625		)	(11,481		)	—		12,058
Private equity investments	49,489		5,206		(7,001		)	(638		)	—		47,056
Real estate	11,230		6		1,843			6,194			—		19,273
Total	$	94,157	$	6,937	$	(7,380	)	$	(10,723	)	$	—	$	82,991

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Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for PSCo is presented in the following table:

(Thousands of Dollars)	2014			2013
Accumulated Benefit Obligation at Dec. 31	$	1,249,739		$	1,134,184
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,152,836		$	1,194,371
Service cost	23,939			25,206
Interest cost	53,277			46,160
Transfer (to) from other plan	(13,404		)	11,306
Actuarial loss (gain)	133,215			(49,384		)
Benefit payments	(71,906		)	(74,823		)
Obligation at Dec. 31	$	1,277,957		$	1,152,836

(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,067,057		$	1,055,308
Actual return on plan assets	84,871			30,684
Employer contributions	35,156			44,582
Transfer (to) from other plan	(11,313		)	11,306
Benefit payments	(71,906		)	(74,823		)
Fair value of plan assets at Dec. 31	$	1,103,865		$	1,067,057

(Thousands of Dollars)	2014			2013
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(174,092	)	$	(85,779	)

^(a)  Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.

(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	530,674		$	450,202
Prior service credit	(18,708		)	(21,800		)
Total	$	511,966		$	428,402

(Thousands of Dollars)	2014		2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	31,774	$	36,271
Noncurrent regulatory assets	480,192		392,131
Total	$	511,966	$	428,402

Measurement date Dec. 31, 2014 Dec. 31, 2013

	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.11	%	4.75	%
Expected average long-term increase in compensation level	3.75		3.75
Mortality table	RP 2014		RP 2000

Mortality — In 2014, the Society of Actuaries published a new mortality table and projection scale that increased the overall life expectancy of males and females. PSCo has reviewed its own population through a credibility analysis and adopted the RP 2014 table with modifications based on its population and specific experience.

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Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2012 through 2015 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

• $90.0 million in January 2015, of which $20.0 million was attributable to PSCo;

• $130.6 million in 2014, of which $35.2 million was attributable to PSCo;

• $192.4 million in 2013, of which $44.6 million was attributable to PSCo; and

• $198.1 million in 2012, of which $41.8 million was attributable to PSCo.

For future years, Xcel Energy and PSCo anticipate contributions will be made as necessary.

Plan Amendments — In 2014 and 2013, there were no plan amendments made which affected the benefit obligation.

Benefit Costs —The components of PSCo’s net periodic pension cost were:

(Thousands of Dollars)	2014			2013			2012
Service cost	$	23,939		$	25,206		$	22,719
Interest cost	53,277			46,160			51,192
Expected return on plan assets	(70,709		)	(63,821		)	(65,302		)
Amortization of prior service (credit) cost	(3,092		)	(1,064		)	228
Amortization of net loss	33,892			43,418			34,332
Net periodic pension cost	$	37,307		$	49,899		$	43,169

	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.75	%	4.00	%	5.00	%
Expected average long-term increase in compensation level	3.75		3.75		4.00
Expected average long-term rate of return on assets	6.81		6.47		6.65

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to PSCo were $9.4 million, $11.6 million and $9.6 million in 2014, 2013 and 2012, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2015 pension cost calculations is 6.81 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for PSCo was approximately $9.1 million in 2014, $8.7 million in 2013 and $8.6 million in 2012.

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Postretirement Health Care Benefits

Xcel Energy, which includes PSCo, has a contributory health and welfare benefit plan that provides health care and death benefits to certain retirees. Xcel Energy discontinued contributing toward health care benefits for former NCE, which includes PSCo, nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

In 1993, Xcel Energy Inc. and PSCo adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years.

Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year:

	2014		2013
Domestic and international equity securities	25	%	41	%
Short-to-intermediate fixed income securities	57		40
Alternative investments	13		13
Cash	5		6
Total	100	%	100	%

Xcel Energy Inc. and PSCo base the investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year.

The following tables present, for each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents (a)	$	23,566	$	—		$	—	$	23,566
Derivatives	—		166			—		166
Government securities	—		43,494			—		43,494
Insurance contracts	—		45,075			—		45,075
Corporate bonds	—		48,527			—		48,527
Asset-backed securities	—		3,240			—		3,240
Mortgage-backed securities	—		10,071			—		10,071
Commingled funds	—		252,790			—		252,790
Other	—		(1,647		)	—		(1,647		)
Total	$	23,566	$	401,716		$	—	$	425,282

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	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents (a)	$	18,202	$	—		$	—	$	18,202
Derivatives	—		(370		)	—		(370		)
Government securities	—		52,028			—		52,028
Insurance contracts	—		47,029			—		47,029
Corporate bonds	—		46,186			—		46,186
Asset-backed securities	—		2,991			—		2,991
Mortgage-backed securities	—		21,593			—		21,593
Commingled funds	—		265,620			—		265,620
Other	—		(15,086		)	—		(15,086		)
Total	$	18,202	$	419,991		$	—	$	438,193

^(a)  Includes restricted cash of $0.9 million and $0.6 million at Dec. 31, 2014 and 2013, respectively.

For the year ended Dec. 31, 2014 there were no assets transferred in or out of Level 3. The following tables present the changes in PSCo’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013 and 2012:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)		Purchases, Issuances and Settlements, Net		Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	670	$	—	$	—	$	—	$	(670	)	$	—
Mortgage-backed securities	35,394		—		—		—		(35,394		)	—
Total	$	36,064	$	—	$	—	$	—	$	(36,064	)	$	—

^(a)  Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2012
Asset-backed securities	$	6,941	$	(293	)	$	1,669		$	(7,647	)	$	—	$	670
Mortgage-backed securities	24,038		(641		)	3,429			8,568			—		35,394
Private equity investments	479		—			(65		)	(414		)	—		—
Real estate	144		—			35			(179		)	—		—
Total	$	31,602	$	(934	)	$	5,068		$	328		$	—	$	36,064

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table:

(Thousands of Dollars)	2014			2013
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	508,971		$	599,831
Service cost	1,915			2,564
Interest cost	23,704			22,210
Medicare subsidy reimbursements	1,753			923
Plan amendments	—			(14,571		)
Plan participants’ contributions	4,625			4,589
Actuarial gain	(63,130		)	(76,889		)
Benefit payments	(34,085		)	(29,686		)
Obligation at Dec. 31	$	443,753		$	508,971

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(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	438,193		$	425,917
Actual return on plan assets	11,060			30,390
Plan participants’ contributions	4,625			4,589
Employer contributions	5,489			6,983
Benefit payments	(34,085		)	(29,686		)
Fair value of plan assets at Dec. 31	$	425,282		$	438,193

(Thousands of Dollars)	2014			2013
Funded Status at Dec. 31:
Funded status (a)	$	(18,471	)	$	(70,778	)

^(a)  Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.

(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	56,823		$	107,232
Prior service credit	(40,189		)	(46,436		)
Total	$	16,634		$	60,796

(Thousands of Dollars)	2014		2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	—	$	8,798
Noncurrent regulatory assets	16,634		51,998
Total	$	16,634	$	60,796

Measurement date Dec. 31, 2014 Dec. 31, 2013

	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.08	%	4.82	%
Mortality table	RP 2014		RP 2000
Health care costs trend rate — initial	6.50	%	7.00	%

Effective Jan. 1, 2015, the initial medical trend rate was decreased from 7.0 percent to 6.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is four years. Xcel Energy Inc. and PSCo base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

A one-percent change in the assumed health care cost trend rate would have the following effects on PSCo:

	One-Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	45,581	$	(38,371	)
Service and interest components	3,028		(2,488		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes PSCo, contributed $17.1 million, $17.6 million and $47.1 million during 2014, 2013 and 2012, respectively, of which $5.5 million, $7.0 million and $27.5 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12.8 million during 2015, of which amounts attributable to PSCo will be zero.

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Plan Amendments — In 2014 there were no plan amendments made which affected the projected benefit obligation. The 2013 decrease of the projected Xcel Energy and PSCo postretirement health and welfare benefit obligation for plan amendments is due to changes in the participant co-pay structure for certain retiree groups.

Benefit Costs — The components of PSCo’s net periodic postretirement benefit costs were:

(Thousands of Dollars)	2014			2013			2012
Service cost	$	1,915		$	2,564		$	2,825
Interest cost	23,704			22,210			24,527
Expected return on plan assets	(30,214		)	(29,227		)	(25,056		)
Amortization of transition obligation	—			785			11,004
Amortization of prior service credit	(6,247		)	(7,666		)	(5,150		)
Amortization of net loss	6,434			13,699			10,930
Net periodic postretirement benefit (credit) cost	(4,408		)	2,365			19,080
Additional cost recognized due to effects of regulation	—			—			3,891
Net benefit (credit) cost recognized for financial reporting	$	(4,408	)	$	2,365		$	22,971

	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.82	%	4.10	%	5.00	%
Expected average long-term rate of return on assets	7.18		7.11		6.75

In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs.

Projected Benefit Payments

The following table lists PSCo’s projected benefit payments for the pension and postretirement benefit plans:

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2015	$	74,237	$	32,300	$	2,532	$	29,768
2016	77,804		32,991		2,692		30,299
2017	77,126		33,328		2,863		30,465
2018	80,003		34,146		3,033		31,113
2019	82,472		34,053		3,192		30,861
2020-2024	423,835		165,560		18,053		147,507

9. Other Income, Net

Other income, net for the years ended Dec. 31 consisted of the following:

(Thousands of Dollars)	2014			2013			2012
Interest income	$	1,470		$	1,761		$	3,603
Other nonoperating income	3,601			2,603			2,233
Insurance policy expense	(806		)	(1,228		)	(1,100		)
Other income, net	$	4,265		$	3,136		$	4,736

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10. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

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 Dec. 31, 2014, accumulated other comprehensive losses related to interest rate derivatives included an immaterial amount 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 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 Dec. 31, 2014, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016.  PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI 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 years ended Dec. 31, 2014 and 2013.

At Dec. 31, 2014, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net 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 Dec. 31:

(Amounts in Thousands)(a)(b)	2014	2013
MWh of electricity	—	326
MMBtu of natural gas	735	6,398
Gallons of vehicle fuel	127	217

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

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

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 Dec. 31, 2014, seven of PSCo’s 10 most significant counterparties for these activities, comprising $35.3 million or 43 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  The remaining three most significant counterparties, comprising $31.0 million or 38 percent of this credit exposure at Dec. 31, 2014, were not rated by these agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.  All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:

(Thousands of Dollars)	2014			2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,338	)	$	(22,871	)	$	(12,377	)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(72		)	9			(9,311		)
After-tax net realized gains on derivative transactions reclassified into earnings	(468		)	(476		)	(1,183		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23,878	)	$	(23,338	)	$	(22,871	)

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The following tables detail the impact of derivative activity during the years ended Dec. 31, 2014, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)				Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—	$	(730	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(115		)	—		(25		)	(b)	—				—
Total	$	(115	)	$	—	$	(755	)		$	—			$	—
Other derivative instruments
Natural gas commodity	$	—		$	451	$	—			$	(4,631	)	(e)	$	(9,850	)	(e)
Total	$	—		$	451	$	—			$	(4,631	)		$	(9,850	)

	Year Ended Dec. 31, 2013
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains)Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	(730	)	(a)	$	—		$	—
Vehicle fuel and other commodity	14		—			(40		)	(b)	—			—
Total	$	14	$	—		$	(770	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—	$	(4,001	)	$	—			$	4,340	(e)	$	5,850	(d)
Total	$	—	$	(4,001	)	$	—			$	4,340		$	5,850

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	Year Ended Dec. 31, 2012
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(15,082	)	$	—	$	(1,819	)	(a)	$	—		$	—
Vehicle fuel and other commodity	63			—		(89		)	(b)	—			—
Total	$	(15,019	)	$	—	$	(1,908	)		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—		$	2		(c)
Natural gas commodity	—			7,727		—				61,820		(e)	(137		)	(d)
Total	$	—		$	7,727	$	—			$	61,820		$	(135	)

^(a)  Amounts are recorded to interest charges.

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

^(e)  Amounts for the year ended Dec. 31, 2012 included $5.0 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.  Such losses for the years ended Dec. 31, 2014 and 2013 were immaterial.  The remaining settlement losses for the years ended Dec. 31, 2014, 2013 and 2012 relate to natural gas operations and are recorded to cost of natural gas sold and transported.  These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2014, 2013 and 2012.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features—Contract provisions for derivative instruments that PSCo enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale 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 Dec. 31, 2014, there were no derivative instruments with contract provisions that required the posting of collateral or settlement of the contracts. If the credit ratings of PSCo were downgraded below investment grade, derivative instruments reflected in a $1.4 million gross liability position on the consolidated balance sheets at Dec. 31, 2013, would have required PSCo to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $1.4 million at Dec. 31, 2013. At Dec. 31, 2013, there was no collateral posted on these specific contracts.

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

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

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

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, PSCo qualified these contracts under the normal purchase exception.  Based 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 Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:

	Dec. 31, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	40	$	—	$	40	$	—		$	40
Other derivative instruments:
Commodity trading	—		2,756		—		2,756		(1,276		)	1,480
Natural gas commodity	—		3,341		—		3,341		—			3,341
Total current derivative assets	$	—	$	6,137	$	—	$	6,137	$	(1,276	)	4,861
PPAs (a)												1,715
Current derivative instruments												$	6,576
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	13	$	—	$	13	$	—		$	13
Total noncurrent derivative assets	$	—	$	13	$	—	$	13	$	—		13
PPAs (a)												6,892
Noncurrent derivative instruments												$	6,905
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	$	1,399
Total current derivative liabilities	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	1,399
PPAs (a)												5,335
Current derivative instruments												$	6,734
Noncurrent derivative liabilities
PPAs (a)												23,366
Noncurrent derivative instruments												$	23,366

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

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013.  At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2014, 2013 and 2012.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2014, 2013 and 2012.

Fair Value of Long-Term Debt

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

	2014				2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,890,229	$	4,328,968	$	3,872,643	$	4,059,661

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The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2014 and 2013, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

11. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — CPUC

Colorado 2014 Electric Rate Case —In 2014, PSCo filed an electric rate case with the CPUC requesting an increase in annual revenue of approximately $136.0 million, or 4.83 percent. The requested 2015 rate increase reflected approximately $100.9 million (subsequently updated to $98.7 million) for recovery of costs associated with the CACJA project. The case also requested the initiation of a CACJA rider for 2016 and 2017, which is anticipated to increase revenue recovery by approximately $34.2 million in 2016 and then decline to approximately $29.9 million in 2017. The rate filing was based on a 2015 forecast test year, a requested ROE of 10.35 percent, an electric rate base of $6.39 billion and an equity ratio of 56 percent. As part of the filing, PSCo would transfer approximately $19.9 million from the transmission rider to base rates, which would not impact customer bills. The rider would recover incremental investment and expenses associated with the CACJA project to retire certain coal plants, add pollution control equipment to other existing coal units and add natural gas generation.

In November 2014, several parties filed answer testimony, including the CPUC Staff (Staff) and the OCC. The Staff’s position was based on an ROE of 9.11 percent and a 51.24 percent equity ratio. In addition, the Staff proposed that costs associated with the CACJA project be recovered through a rider mechanism. The OCC recommended an ROE of 9.10 percent, a 52.70 percent equity ratio and that a portion of the costs associated with the CACJA project be recovered in base rates and the remainder through a rider mechanism.

In December 2014, PSCo filed rebuttal testimony, revising its requested rate increase to $107.2 million, or 3.79 percent, reflecting an ROE of 10.25 percent and updated information for both the sales and property tax forecasts. PSCo also proposed to recover all costs associated with the CACJA project through the rider beginning in 2015.

On Jan. 23, 2015, PSCo and intervenors filed a comprehensive settlement agreement, subject to CPUC approval, which would result in an overall 2015 revenue increase of approximately $53.3 million, or 1.87 percent. Key terms of the agreement include the following:

• The settlement is based on a 2013 HTY, an ROE of 9.83 percent and an equity ratio of 56 percent;

• It includes the implementation of a forward-looking CACJA rider, effective Jan. 1, 2015, a forward-looking TCA rider, effective Feb. 13, 2015 and tracking mechanisms for pension expense and property taxes; and

• The agreement also includes an earnings test for 2015 through 2017, under which PSCo and customers would share in any earnings on a 50/50 basis if the ROE recognized falls between 9.84 percent and 10.48 percent. The earnings test principles are based primarily on those established in the previous rate case.

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The Staff and OCC’s recommendations, PSCo’s rebuttal testimony and the terms of the settlement agreement are summarized as follows:

2015 Rate Request (Millions of Dollars)	Staff			OCC			PSCo Rebuttal			Settlement Agreement
PSCo’s filed rate request	$	136.0		$	136.0		$	136.0		$	136.0
Transfer from TCA rider to base rates	19.9			19.9			19.9			19.9
PSCo’s filed revenue requirement deficiency	155.9			155.9			155.9			155.9
Lower ROE	(69.1		)	(66.5		)	(6.2		)	(27.9		)
Capital structure	(20.9		)	(23.7		)	—			—
Rate base adjustments (largely the removal of prepaid pension asset)	(20.8		)	2.3			—			—
Adjustment to an HTY	(82.5		)	(82.5		)	—			(23.9		)
Adjustment to use 13-month average rate base	(26.1		)	(22.0		)	—			—
Rate base adjustments for known and measurable plant through September 2014	21.9			—			—			—
O&M expense adjustments	(7.2		)	(16.6		)	—			—
Depreciation	—			(3.8		)	—			—
Property taxes	—			(12.1		)	(5.3		)	(5.3		)
Remove CACJA from base rates	(62.4		)	—			(98.7		)	(98.7		)
Updated sales forecast	—			—			(15.2		)	(15.2		)
Prepaid pension amortization	—			—			—			9.5
Non-specified settlement adjustments	—			—			—			(31.7		)
Other, net	0.1			0.1			(2.1		)	(2.1		)
Total base rate (decrease) increase	(111.1		)	(68.9		)	28.4			(39.4		)
CACJA rider mechanism	54.2			—			98.7			97.0
TCA rider mechanism — 2015 forecast test year	—			—			—			15.6
Transfer from TCA rider to base rates	(19.9		)	(19.9		)	(19.9		)	(19.9		)
Total revenue impact	$	(76.8	)	$	(88.8	)	$	107.2		$	53.3

In addition to the revenue reflected in the table above, PSCo estimates that it will defer approximately $3.1 million of additional expenses in 2015 as a result of the settlement.

In its original rate case request, PSCo proposed to shorten the depreciable lives for certain assets, which would have resulted in a material increase in depreciation expense. As a result of the settlement, PSCo will not implement the depreciation changes, but will instead file a standalone case to address depreciation, amortization and decommissioning in early 2016. The results of the depreciation case will become effective as part of the 2018 electric rate case.

Settlement rates became effective Feb. 13, 2015 on an interim basis, subject to refund, and the CPUC is expected to issue a final decision regarding the settlement in the first quarter of 2015.

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

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

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Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012-2014. In April 2014, PSCo filed its 2013 earnings test with the CPUC proposing a refund obligation of $45.7 million to electric customers. This tariff was approved by the CPUC in July 2014. As of Dec. 31, 2014, PSCo has also recognized management’s best estimate of the expected customer refund obligation for the 2014 earnings test of $74.0 million. PSCo will file its 2014 earnings test with the CPUC in April 2015. The final sharing obligation will be based on the CPUC-approved tariff and could vary from the current estimate.

SmartGridCity (SGC) Cost Recovery — PSCo requested recovery of $45 million of capital costs and $4 million of annual O&M costs incurred to develop and operate SGC as part of its 2010 electric rate case.  In 2011, the CPUC allowed recovery of approximately $28 million of the capital cost and all of the O&M costs.  PSCo subsequently requested recovery of the remaining capital investment in SGC, which the CPUC denied in April 2013.  Based on the ALJ’s previous recommended decision to deny recovery, PSCo recognized a $10.7 million pre-tax charge in 2012, representing the net book value of the disallowed investment, which was included in O&M expense.

Electric, Purchased Gas and Resource Adjustment Clauses

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

The CPUC approved the 2014 PSCo electric and gas DSM budget of $87.8 million and $12.3 million, respectively. In October 2014, PSCo filed its 2015-2016 DSM plan, which proposes a 2015 DSM electric budget of $81.6 million and a gas budget of $13.1 million and a 2016 DSM electric budget of $78.7 million and gas budget of $13.6 million. A decision by the ALJ is expected in the second quarter of 2015.

REC Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent to customers for 2014. In 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. PSCo credited to the RESA regulatory asset balance approximately $0.6 million and $21.7 million in 2014 and 2013, respectively. The cumulative credit to the RESA regulatory asset balance was $105.1 million and $104.5 million at Dec. 31, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds.

In September 2014, an ALJ issued a decision approving a settlement between PSCo, the CPUC Staff, and intervenors to extend the current sharing mechanism without modification through 2017.

Recently Concluded Regulatory Proceedings — FERC

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

In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures. Several wholesale customers then filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012.

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In September 2014, PSCo and its transmission customers filed a settlement to resolve the ROE issue in the transmission rate filing and complaint. The FERC approved the settlement in October 2014, providing a 9.72 percent ROE effective retroactive to July 1, 2012 for the PSCo transmission formula rate. Refunds were provided to customers in December 2014.

Production Formula Rate ROE Complaint — In August 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo production sales formula rates effective Sept. 1, 2013. In September 2014, PSCo and its wholesale customers filed a settlement to resolve the complaint along with the pending transmission formula rate ROE matters. The FERC approved the settlement in October 2014, providing a 9.72 percent ROE effective for the PSCo production formula rate. Refunds were provided to customers in December 2014.

12. Commitments and Contingencies

Commitments

Capital Commitments — PSCo has made commitments in connection with a portion of its projected capital expenditures. PSCo’s capital commitments primarily relate to the following major project.

Gas Transmission Integrity Management Programs – PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include primarily system renewal projects.

Fuel Contracts— PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2015 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.

The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2014, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2015	$	321.0	$	298.3	$	136.3
2016	261.3		153.0		79.6
2017	193.6		158.8		54.8
2018	42.4		212.3		53.9
2019	43.2		221.7		51.8
Thereafter	384.0		732.7		831.1
Total	$	1,245.5	$	1,776.8	$	1,207.5

Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. PSCo’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

PPAs— PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2032 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.

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Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $69.5 million, $72.7 million and $119.5 million in 2014, 2013 and 2012, respectively. At Dec. 31, 2014, the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:

(Millions of Dollars)	Capacity		Energy (a)
2015	$	82.9	$	49.5
2016	58.4		22.5
2017	35.0		4.0
2018	27.8		—
2019	19.0		—
Thereafter	47.6		—
Total	$	270.7	$	76.0

^(a)  Excludes contingent energy payments for renewable energy PPAs.

Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.

Leases— PSCo leases a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair-market value or the present value of future lease payments and are amortized over the term of the contract.

WYCO was formed as a joint venture between Xcel Energy Inc. and Colorado Interstate Gas Company, LLC (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO, and PSCo has no direct ownership interest. WYCO generally leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $138.9 million and $144.2 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2014 and 2013, respectively.

PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $7.2 million, $6.3 million, and $5.7 million for 2014, 2013 and 2012, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(49.0		)	(41.8		)
Total property held under capital leases, net	$	172.2		$	179.4

The remainder of the leases, primarily for certain PPAs, office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment are accounted for as operating leases. Total expenses under operating lease obligations were approximately $126.2 million, $96.6 million and $77.9 million for 2014, 2013 and 2012, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $110.1 million, $79.6 million and $59.4 million in 2014, 2013 and 2012, respectively, recorded to electric fuel and purchased power expenses.

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Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are:

(Millions of Dollars)	Operating Leases		PPA (a) (b) Operating Leases		Total Operating Leases		Capital Leases
2015	$	14.5	$	113.8	$	128.3	$	30.5
2016	11.7		102.8		114.5		29.3
2017	7.0		96.5		103.5		25.6
2018	6.7		96.7		103.4		25.3
2019	6.6		97.6		104.2		25.1
Thereafter	41.8		688.0		729.8		511.5
Total minimum obligation							647.3
Interest component of obligation							(475.1		)
Present value of minimum obligation							$	172.2

^(a)  Amounts do not include PPAs accounted for as executory contracts.

^(b)  PPA operating leases contractually expire through 2032.

Variable Interest Entities— The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

PPAs — Under certain PPAs, PSCo purchases power from independent power producing entities 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 has determined that certain independent power producing entities are variable interest entities. PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future, required to be provided other than contractual payments for energy and capacity set forth in the PPAs.

PSCo has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. 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. PSCo had approximately 1,802 MW and 1,441 MW of capacity under long-term PPAs as of Dec. 31, 2014, and 2013, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032.

Environmental Contingencies

PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense.

Site Remediation— Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent hazardous materials and wastes to that site.

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MGP Sites— PSCo is currently involved in investigating and/or remediating several MGP sites where hazardous or other regulated materials may have been deposited. PSCo has identified two sites where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. PSCo anticipates that the majority of the remediation at these sites will continue through at least 2015. PSCo had accrued $1.8 million and $1.2 million for both of these sites at Dec. 31, 2014 and 2013, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and Waste

Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. PSCo has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017, but no later than July 2022. The impact of this rule on PSCo is uncertain at this time.

Federal CWA Section 316(b) — Section 316(b) of the federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. At Dec. 31, 2014, the estimated cost of compliance for PSCo did not have a material impact on the results of operations, financial position or cash flows.

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

Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2010, the EPA published a proposed rule on the regulation of coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. The EPA issued a pre-publication version of the final rule in December 2014, which once promulgated will impose new rules to regulate coal ash as a nonhazardous solid waste. PSCo’s costs for the management and disposal of coal ash will not significantly increase under the new rule.

Air

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

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GHG NSPS Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. A final rule is anticipated in mid-summer 2015. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

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

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. PSCo expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. It is not yet known what impact the Supreme Court’s decision may have on the MATS standard or its implementation schedule. PSCo believes EGU MATS costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. In 2005, the EPA amended the 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 SIP, Colorado identified the PSCo facilities that will have to reduce SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a SIP that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Installation of emission controls at Pawnee was completed in 2014 at a cost of $272.6 million. Installation of the emission controls at Hayden Unit 1 is scheduled for 2015 and Hayden Unit 2 is scheduled for 2016 at an estimated combined cost of $84.6 million. PSCo anticipates these costs will be fully recoverable in rates.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10^th Circuit to review the EPA’s decision approving the SIP. WildEarth Guardians has stated it will challenge the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that SCR be added to the units. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October 2014, the Court granted the EPA’s request and vacated the current briefing schedule. The EPA has provided required status reports.

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

Revisions to the National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where PSCo operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In December 2014, the EPA issued its final designations, which did not include areas in Colorado.

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Revisions to the NAAQS for Ozone— In December 2014, the EPA proposed to revise the NAAQS for ozone by lowering the eight-hour standard from 0.075 parts per million (ppm) to a level within the range of 0.065-0.070 ppm. The EPA is also taking comment on a level for the standard as low as 0.060 ppm. In Colorado, current monitored air quality concentrations are above the proposed level of 0.070 ppm in the Denver Metropolitan Area. The EPA is expected to adopt a new ozone standard in a final rule to be issued in October 2015. Depending on the level of the standard, impacted states would study the sources of the nonattainment and make emission reduction plans to attain the standards. These plans would be due to the EPA in 2020 or 2021. Such plans could include installation of further NOx controls on power plants. It is not possible to evaluate the impact of this proposal until the final standard is adopted, the designation of nonattainment areas is made in late 2017 based on air quality data years 2014-2016, and any required state plans are developed.

NOV — In 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Generating Station in Colorado. The NOV alleges that various maintenance, repair and replacement projects at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this NOV.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, wind, other and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, natural gas storage and common general property. The electric production obligations include asbestos, ash-containment facilities, radiation sources, storage tanks, control panels. The asbestos recognition associated with the electric production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. The AROs recorded for PSCo steam and other production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination dates on the ARO recognition for ash-containment facilities at steam plants were the in-service dates of the various facilities. PSCo has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract, with the origination dates being the in-service date of the various facilities.

PSCo recognized an ARO for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering, extraction and wells related to gas storage facilities. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks, radiation sources and office buildings. These assets have numerous in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

In December 2014, the EPA issued a pre-publication version of a final rule imposing requirements for activities involving coal ash waste. The ruling, once effective, will not result in the creation of a new legal obligation and PSCo’s estimated cash flows for the closure of coal ash landfills and impoundments are not expected to significantly increase as a result of the ruling.

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A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2014 and 2013 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow Revisions			Ending Balance  Dec. 31, 2014 (a)
Electric plant
Steam and other production asbestos	$	23,914	$	747	$	1,597	$	10,598		$	36,856
Steam and other production ash containment	29,234		—		1,897		30,754			61,885
Wind production	2,953		—		22		(880		)	2,095
Electric distribution	1,176		—		43		(37		)	1,182
Other	1,017		—		41		92			1,150
Natural gas plant
Gas transmission and distribution	788		18,252		50		98,384			117,474
Other	575		2,865		24		422			3,886
Common and other property
Common miscellaneous	741		—		27		—			768
Total liability	$	60,398	$	21,864	$	3,701	$	139,333		$	225,296

^(a)  There were no ARO liabilities settled during the year ended Dec. 31, 2014.

(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions			Ending Balance Dec. 31, 2013
Electric plant
Steam and other production asbestos	$	19,734	$	—	$	(941	)	$	1,247	$	3,874		$	23,914
Steam and other production ash containment	12,919		—		—			684		15,631			29,234
Wind production	2,928		—		—			25		—			2,953
Electric distribution	6,392		—		—			178		(5,394		)	1,176
Other	627		—		—			60		330			1,017
Natural gas plant
Gas transmission and distribution	842		—		—			53		(107		)	788
Other	—		575		—			—		—			575
Common and other property
Common miscellaneous	309		—		—			29		403			741
Total liability	$	43,751	$	575	$	(941	)	$	2,276	$	14,737		$	60,398

Indeterminate AROs—PSCo has certain underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined; therefore, an ARO has not been recorded for these facilities.

Removal Costs — PSCo records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2014 and 2013 were $366 million and $359 million, respectively.

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Legal Contingencies

PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

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

In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC issued an order on remand establishing principles for the review proceeding in October 2011. In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012.

In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive.

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

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Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, notwithstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter.

Other Contingencies

See Note 11 for further discussion.

13. Regulatory Assets and Liabilities

PSCo’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of PSCo no longer allow for the application of regulatory accounting guidance under GAAP, PSCo would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.

The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2014 and 2013 were:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	32,195	$	500,889	$	45,504	$	447,752
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		141,214		—		116,477
Contract valuation adjustments (b)	10	Term of related contract	8,901		12,999		3,620		16,474
Depreciation differences	1	One to seventeen years	10,700		104,743		10,917		95,844
Net AROs (c)	1, 12	Plant lives	—		46,213		—		39,986
Conservation programs (d)	1, 11	One to five years	10,198		10,906		13,883		19,430
Gas pipeline inspection costs	12	One to four years	5,416		3,611		5,416		14,978
Renewable resources and environmental initiatives	12	One to two years	—		—		22,325		—
Purchased power contract costs	12	Term of related contract	858		29,596		—		30,069
Losses on reacquired debt	4	Term of related debt	1,426		8,378		1,572		9,804
Recoverable purchased natural gas and electric energy costs	1	Less than one year	18,410		—		18,022		—
Property tax		One to three years	28,024		31,429		18,427		30,626
Other		Various	3,992		13,995		10,477		4,597
Total regulatory assets			$	120,120	$	903,973	$	150,163	$	826,037

^(a)  Includes $4.5 million and $4.1 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2014 and 2013, respectively.

^(b)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(c)  Includes amounts recorded for future recovery of AROs.

^(d)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2014 and 2013 were:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	366,359	$	—	$	359,387
Deferred electric, gas and steam production costs	1	Less than one year	24,035		—		33,247		—
Investment tax credit deferrals	1, 7	Various	—		22,225		—		24,038
Deferred income tax adjustment	1	Various	—		18,672		—		18,770
Conservation programs (a)	1, 11	Less than one year	32,226		—		12,188		—
Renewable resources and environmental initiatives	11, 12	Various	3,308		10,376		—		1,412
Low income discount program		Less than one year	1,680		—		4,084		—
Gain from asset sales		One to three years	316		4		1,687		368
PSCo earnings test	11	One to two years	57,127		42,819		22,892		19,203
Gas pipeline inspection costs	12	One to four years	13,970		642		—		—
Other		Various	1,797		3,324		5,401		1,512
Total regulatory liabilities			$	134,459	$	464,421	$	79,499	$	424,690

^(a)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

At Dec. 31, 2014 and 2013, approximately $104 million and $136 million of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with renewable resources and environmental initiatives.

14. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2014			Year Ended Dec. 31, 2013
Accumulated other comprehensive loss at Jan. 1	$	(23,338	)	$	(22,871	)
Other comprehensive (loss) income before reclassifications	(72		)	9
Gains reclassified from net accumulated other comprehensive loss	(468		)	(476		)
Net current period other comprehensive loss	(540		)	(467		)
Accumulated other comprehensive loss at Dec. 31	$	(23,878	)	$	(23,338	)

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2014				Year Ended Dec. 31, 2013
Gains on cash flow hedges:
Interest rate derivatives	$	(730	)	(a)	$	(730	)	(a)
Vehicle fuel derivatives	(25		)	(b)	(40		)	(b)
Total, pre-tax	(755		)		(770		)
Tax expense	287				294
Total amounts reclassified, net of tax	$	(468	)		$	(476	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

79

15. Segments and Related Information

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

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

• PSCo’s regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s commodity trading operations.

• PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado.

• Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities.

Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from 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.

The accounting policies of the segments are the same as those described in Note 1.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2014
Operating revenues (a)	$	3,125,937	$	1,215,324	$	41,888		$	—		$	4,383,149
Intersegment revenues	339		180		—			(519		)	—
Total revenues	$	3,126,276	$	1,215,504	$	41,888		$	(519	)	$	4,383,149
Depreciation and amortization	$	285,968	$	89,186	$	4,048		$	—		$	379,202
Interest charges and financing costs	124,118		29,987		535			—			154,640
Income tax expense (benefit)	208,095		50,874		(15,378		)	—			243,591
Net Income	349,793		84,324		21,071			—			455,188

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2013
Operating revenues (a)	$	3,081,171	$	1,080,703	$	40,754		$	—		$	4,202,628
Intersegment revenues	302		110		—			(412		)	—
Total revenues	$	3,081,473	$	1,080,813	$	40,754		$	(412	)	$	4,202,628
Depreciation and amortization	$	280,972	$	75,510	$	3,935		$	—		$	360,417
Interest charges and financing costs	129,787		30,604		554			—			160,945
Income tax expense (benefit)	220,356		42,294		(11,910		)	—			250,740
Net income	368,586		69,682		15,115			—			453,383

80

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2012
Operating revenues (a)	$	2,969,899	$	962,435	$	36,959		$	—		$	3,969,293
Intersegment revenues	282		90		—			(372		)	—
Total revenues	$	2,970,181	$	962,525	$	36,959		$	(372	)	$	3,969,293
Depreciation and amortization	$	267,944	$	66,983	$	3,900		$	—		$	338,827
Interest charges and financing costs	145,641		33,430		618			—			179,689
Income tax expense (benefit)	212,347		27,968		(7,771		)	—			232,544
Net income	387,724		60,003		10,349			—			458,076

^(a)  Operating revenues include $14 million, $13 million and $14 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012, respectively. See Note 16 for further discussion of related party transactions by reportable segment.

16. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 4 for further discussion.

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Thousands of Dollars)	2014		2013		2012
Operating revenues:
Electric	$	9,614	$	8,136	$	9,271
Other	4,441		4,441		4,441
Operating expenses:
Purchased power	23		1,331		6,539
Other operating expenses — paid to Xcel Energy Services Inc.	454,250		375,766		316,548
Interest expense	158		132		114
Interest income	61		273		122

Accounts receivable and payable with affiliates at Dec. 31 were:

	2014				2013
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	6,706	$	18,065	$	—
NSP-Wisconsin	22		—		8		—
SPS	5,803		—		1,056		—
Other subsidiaries of Xcel Energy Inc.	45,017		40,030		7		45,902
	$	50,842	$	46,736	$	19,136	$	45,902

17. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2014
Operating revenues	$	1,203,543	$	993,704	$	1,049,111	$	1,136,791
Operating income	208,437		163,437		261,073		169,423
Net income	118,403		89,792		154,159		92,834

81

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
Operating revenues	$	1,117,457	$	966,429	$	1,044,300	$	1,074,442
Operating income	212,299		183,675		289,741		143,044
Net income	116,605		97,299		166,266		73,213

Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A — 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 Dec. 31, 2014, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting.  PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting.  PSCo has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.  During the year and in preparation for issuing its report for the year ended Dec. 31, 2014 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, PSCo conducted testing and monitoring of its internal control over financial reporting.  Based on the control evaluation, testing and remediation performed, PSCo did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

This annual report does not include an attestation report of PSCo’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s independent registered public accounting firm pursuant to the rules of the SEC that permit PSCo to provide only management’s report in this annual report.

Item 9B — Other Information

None.

PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for PSCo in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13 — Certain Relationships and Related Transactions, and Director Independence

82

Item 14 — Principal Accountant Fees and Services

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2015 Annual Meeting of Shareholders, which is incorporated by reference.

83

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Consolidated Financial Statements:
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2014.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2014, 2013, and 2012.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2014, 2013, and 2012.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2014, 2013, and 2012.
	Consolidated Balance Sheets — As of Dec. 31, 2014 and 2013.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Consolidated Statements of Capitalization — As of Dec. 31, 2014 and 2013.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2014, 2013, and 2012.
3.	Exhibits

*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
t	Certain portions of this agreement have been omitted pursuant to a request for confidential treatment and have been filed separately with the SEC.

2.01* t	Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as Sellers, and PSCo, as Purchaser, dated as of April 2, 2010 (excluding certain schedules and exhibits referred to in the agreement, as amended, which the Registrant agrees to furnish supplemental to the SEC upon request) (Exhibit 2.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2010).
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)).
4.01*	Indenture, dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
4.02*	Indentures supplemental to Indenture dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee:

Dated as of	Previous Filing: Form; Date or file no.	Exhibit No.
Nov. 1, 1993	S-3, (33-51167)	4(b)(2)
Jan. 1, 1994	10-K, 1993	4(b)(3)
Sept. 2, 1994	8-K, September 1994	4(b)
Nov. 1, 1996	10-K, 1996 (001-03280)	4(b)(3)
Feb. 1, 1997	10-Q, March 31, 1997 (001-03280)	4(a)
April 1, 1998	10-Q, March 31, 1998 (001-03280)	4(b)
Aug. 15, 2002	10-Q, Sept. 30, 2002 (001-03280)	4.03
Aug. 1, 2005	PSCo 8-K, Aug. 18, 2005 (001-03280)	4.02

4.03*	Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and First Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
4.04*	Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129.5 million Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file no. 001-03280).
4.05*	Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust National Association, as successor Trustee (Exhibit 4.01 to PSCo Form 8-K (file no. 001-03280) dated Aug. 18, 2007).

84

4.06*	Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of 5.80 percent First Mortgage Bonds, Series No. 18 due 2018 and $300 million principal amount of 6.50 percent First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)).
4.07*	Supplemental Indenture dated as of May 1, 2009 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $400 million principal amount of 5.125 percent First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)).
4.08*	Supplemental Indenture dated as of Nov. 1, 2010 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of 3.200 percent First Mortgage Bonds, Series No. 21 due 2020 (Exhibit 4.01 of Form 8-K of PSCo dated Nov. 18, 2010 (file no. 001-03280)).
4.09*	Supplemental Indenture dated as of Aug. 1, 2011 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 4.75 percent First Mortgage Bonds, Series No. 22 due 2041 (Exhibit 4.01 to Form 8-K of PSCo dated Aug. 9, 2011 (file no. 001-03280)).
4.10*	Supplemental Indenture dated as of Sept. 1, 2012 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 2.25 percent First Mortgage Bonds, Series No. 23 due 2022 and $500 million principal amount of 3.60 percent First Mortgage Bonds, Series No. 24 due 2042 (Exhibit 4.01 to Form 8-K dated Sept. 11, 2012 (file no. 001-03280)).
4.11*	Supplemental Indenture dated as of March 1, 2013 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.50 percent First Mortgage Bonds, Series No. 25 due 2023 and $250 million principal amount of 3.95 percent First Mortgage Bonds, Series No. 26 due 2043 (Exhibit 4.01 to Form 8-K of PSCo dated March 26, 2013 (file no. 001-03280)).
4.12*	Supplemental Indenture dated as of March 1, 2014 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 4.30 percent First Mortgage Bonds, Series No. 27 due 2044. (Exhibit 4.01 to Form 8-K of PSCo dated March 10, 2014 (file no. 001-03280)).
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Xcel Energy Inc. Non-Employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.05*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*	Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10(c)(1)).
10.07*	First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10(c)(2)).
10.08*	Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K of Xcel Energy (file no. 001-03034) dated Dec. 3, 2004).
10.09*	Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K of Xcel Energy (file no. 001-03034) dated Dec. 3, 2004).
10.10*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.11*+	Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.12*+	Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.13*+	Xcel Energy Inc. 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
10.14*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.15*+	Xcel Energy Inc. 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).

85

10.16*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.17*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.18a*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.18b*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Time-Based Restricted Stock Unit Agreement (Exhibit 10.14b to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2012).
10.19*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed Apr. 5, 2011).
10.20*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.21*+	First Amendment effective Nov. 29, 2011 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.22*+	Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.23*+	First Amendment dated Feb. 20, 2013 to the Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.24*+	Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.25*+	First Amendment dated May 21, 2013 to the Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-Q of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.26*+	Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to Form 10-Q of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.27*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.28*	Amended and Restated Credit Agreement, dated as of Oct. 14, 2014 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.03 to Form 8-K of Xcel Energy, dated Oct. 14, 2014 (file no. 001-03034)).

12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification 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 certification 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 Annual Report on Form 10-K for the year ended Dec. 31, 2014 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) the Consolidated Statements of Capitalization, (vii) Notes to Consolidated Financial Statements, (viii) document and entity information, and (ix) Schedule II.

86

SCHEDULE II

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2014, 2013 AND 2012

(amounts in thousands)

			Additions
	Balance at Jan. 1		Charged to Costs and Expenses		Charged to Other Accounts(a)		Deductions from Reserves(b)		Balance at Dec. 31
Allowance for bad debts:
2014	$	22,505	$	17,005	$	6,240	$	22,628	$	23,122
2013	21,918		16,784		7,005		23,202		22,505
2012	24,698		16,323		7,648		26,751		21,918

^(a)  Recovery of amounts previously written off.

^(b)  Principally bad debts written off.

87

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.

	PUBLIC SERVICE COMPANY OF COLORADO
Feb. 20, 2015	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Executive Vice President, Chief Financial Officer and Director
	(Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.

/s/ BEN FOWKE	/s/ DAVID L. EVES
Ben Fowke	David L. Eves
Chairman, Chief Executive Officer and Director	President and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN	/s/ JEFFREY S. SAVAGE
Teresa S. Madden	Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director	Senior Vice President, Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ MARVIN E. MCDANIEL, JR.
Marvin E. McDaniel, Jr.
Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

PSCo has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

88

EX-12.01

Exhibit 12.01

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

STATEMENT OF COMPUTATION OF

RATIO OF EARNINGS TO FIXED CHARGES

(amounts in thousands, except ratio)

	Year Ended Dec. 31
	2014		2013		2012		2011		2010
Earnings, as defined:
Pretax income	$	698,779	$	704,123	$	690,620	$	625,164	$	628,901
Add: Fixed charges	232,832		232,539		254,443		253,867		233,604
Total earnings, as defined	$	931,611	$	936,662	$	945,063	$	879,031	$	862,505
Fixed charges, as defined:
Interest charges	$	171,881	$	173,602	$	188,094	$	186,885	$	171,945
Interest charges on life insurance policy borrowings	214		245		310		332		372
Interest component of leases	60,737		58,692		66,039		66,650		61,287
Total fixed charges, as defined	$	232,832	$	232,539	$	254,443	$	253,867	$	233,604
Ratio of earnings to fixed charges	4.0		4.0		3.7		3.5		3.7

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-191629 on Form S-3 of our report dated February 20, 2015, relating to the consolidated financial statements and financial statement schedule of Public Service Company of Colorado and subsidiaries appearing in this Annual Report on Form 10-K of Public Service Company of Colorado for the year ended December 31, 2014.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 20, 2015

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

1. I have reviewed this report on Form 10-K 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: Feb. 20, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-K 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: Feb. 20, 2015

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Public Service Company of Colorado (PSCo) on Form 10-K for the year ended Dec. 31, 2014, as filed with the SEC on the date hereof (Form 10-K), 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-K 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-K 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-K.

Date: Feb. 20, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

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

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

1

EX-99.01

Exhibit 99.01

Public Service Company of Colorado Cautionary Factors

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

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

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

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

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

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

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

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

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

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

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

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

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

• Social attitudes regarding the utility and power industries;

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

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

• Risks associated with implementations of new technologies; and

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

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

XML

Rate Matters (Tables)

12 Months Ended

Dec. 31, 2014

Public Utilities, General Disclosures [Abstract]

PSCo 2014 Electric Rate Case

The Staff and OCC’s recommendations, PSCo’s rebuttal testimony and the terms of the settlement agreement are summarized as follows:

2015 Rate Request (Millions of Dollars)	Staff			OCC			PSCo Rebuttal			Settlement Agreement
PSCo’s filed rate request	$	136.0		$	136.0		$	136.0		$	136.0
Transfer from TCA rider to base rates	19.9			19.9			19.9			19.9
PSCo’s filed revenue requirement deficiency	155.9			155.9			155.9			155.9
Lower ROE	(69.1		)	(66.5		)	(6.2		)	(27.9		)
Capital structure	(20.9		)	(23.7		)	—			—
Rate base adjustments (largely the removal of prepaid pension asset)	(20.8		)	2.3			—			—
Adjustment to an HTY	(82.5		)	(82.5		)	—			(23.9		)
Adjustment to use 13-month average rate base	(26.1		)	(22.0		)	—			—
Rate base adjustments for known and measurable plant through September 2014	21.9			—			—			—
O&M expense adjustments	(7.2		)	(16.6		)	—			—
Depreciation	—			(3.8		)	—			—
Property taxes	—			(12.1		)	(5.3		)	(5.3		)
Remove CACJA from base rates	(62.4		)	—			(98.7		)	(98.7		)
Updated sales forecast	—			—			(15.2		)	(15.2		)
Prepaid pension amortization	—			—			—			9.5
Non-specified settlement adjustments	—			—			—			(31.7		)
Other, net	0.1			0.1			(2.1		)	(2.1		)
Total base rate (decrease) increase	(111.1		)	(68.9		)	28.4			(39.4		)
CACJA rider mechanism	54.2			—			98.7			97.0
TCA rider mechanism — 2015 forecast test year	—			—			—			15.6
Transfer from TCA rider to base rates	(19.9		)	(19.9		)	(19.9		)	(19.9		)
Total revenue impact	$	(76.8	)	$	(88.8	)	$	107.2		$	53.3

XML

Preferred Stock (Details) (USD $)	Dec. 31, 2014
Equity [Abstract]
Preferred stock, shares authorized (in shares)	10,000,000
Preferred stock, par value (in dollars per share)	$ 0.01
Preferred stock, shares outstanding (in shares)	0

XML

Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Public Utilities, Inventory [Line Items]
Inventories	$ 238,979	$ 238,007
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	55,491	53,127
Fuel
Public Utilities, Inventory [Line Items]
Inventories	80,963	86,062
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 102,525	$ 98,818

XML

Other Income, Net (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Income and Expenses [Abstract]
Interest income	$ 1,470	$ 1,761	$ 3,603
Other nonoperating income	3,601	2,603	2,233
Insurance policy expense	(806)	(1,228)	(1,100)
Other income, net	$ 4,265	$ 3,136	$ 4,736

XML

Joint Ownership of Generation, Transmission and Gas Facilities (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 1,428,689
Accumulated depreciation	345,808
Construction work in progress	16,049
Generating capacity (in MW)	820
Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant [Abstract]
Plant in service	98,145
Accumulated depreciation	66,333
Construction work in progress	1,405
Ownership percentage (in hundredths)	75.50%
Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant [Abstract]
Plant in service	121,571
Accumulated depreciation	59,999
Construction work in progress	8,867
Ownership percentage (in hundredths)	37.40%
Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant [Abstract]
Plant in service	37,049
Accumulated depreciation	16,928
Construction work in progress	135
Ownership percentage (in hundredths)	53.10%
Electric Generation | Craig Units 1 and 2
Jointly Owned Utility Plant [Abstract]
Plant in service	59,860
Accumulated depreciation	35,573
Construction work in progress	3,013
Ownership percentage (in hundredths)	9.70%
Electric Generation | Craig Common Facilities 1, 2 and 3
Jointly Owned Utility Plant [Abstract]
Plant in service	36,890
Accumulated depreciation	17,735
Construction work in progress	527
Ownership percentage (in hundredths)	6.50%
Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant [Abstract]
Plant in service	883,971
Accumulated depreciation	81,748
Construction work in progress	64
Ownership percentage (in hundredths)	66.70%
Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant [Abstract]
Plant in service	23,624
Accumulated depreciation	1,051
Construction work in progress	308
Ownership percentage (in hundredths)	82.00%
Electric Transmission | Transmission and other facilities, including substations
Jointly Owned Utility Plant [Abstract]
Plant in service	151,301
Accumulated depreciation	60,847
Construction work in progress	1,730
Ownership percentage of group of jointly owned facilities	Various
Gas Transportation | Rifle to Avon
Jointly Owned Utility Plant [Abstract]
Plant in service	16,278
Accumulated depreciation	5,594
Construction work in progress	$ 0
Ownership percentage (in hundredths)	60.00%

XML

Commitments and Contingencies, Fuel Contracts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2015
Maximum [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2060
Coal [Member]
Fuel Contracts [Abstract]
2015	321.0
2016	261.3
2017	193.6
2018	42.4
2019	43.2
Thereafter	384.0
Total	1,245.5
Natural Gas Supply [Member]
Fuel Contracts [Abstract]
2015	298.3
2016	153.0
2017	158.8
2018	212.3
2019	221.7
Thereafter	732.7
Total	1,776.8
Natural Gas Storage and Transportation [Member]
Fuel Contracts [Abstract]
2015	136.3
2016	79.6
2017	54.8
2018	53.9
2019	51.8
Thereafter	831.1
Total	1,207.5

XML

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Conservation Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	2.70%	2.80%	2.60%
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents	3 months

XML

Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Preferred Stock

PSCo has authorized the issuance of preferred stock.

Preferred Shares Authorized	Par Value		Preferred Shares Outstanding
10,000,000	$	0.01	None

XML

Commitments and Contingencies, Purchased Power Agreements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Capacity
Purchased Power Agreements [Abstract]
Payments for capacity	$ 69.5		$ 72.7	$ 119.5
Estimated Future Payments Under PPAs [Abstract]
2015	82.9
2016	58.4
2017	35.0
2018	27.8
2019	19.0
Thereafter	47.6
Total	270.7
Energy
Estimated Future Payments Under PPAs [Abstract]
2015	49.5	[1]
2016	22.5	[1]
2017	4.0	[1]
2018	0	[1]
2019	0	[1]
Thereafter	0	[1]
Total	$ 76.0	[1]
Maximum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchase Power Agreement Duration, Maximum	2032

[1] Excludes contingent energy payments for renewable energy PPAs

XML

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 0	$ 1,400,000
Payments required if credit ratings were downgraded below investment grade		1,400,000
Collateral posted on derivative instruments	0	0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

XML

Segments and Related Information (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Intercompany revenue									$ 14,000,000		$ 13,000,000		$ 14,000,000
Operating revenues	1,136,791,000	1,049,111,000	993,704,000	1,203,543,000	1,074,442,000	1,044,300,000	966,429,000	1,117,457,000	4,383,149,000		4,202,628,000		3,969,293,000
Depreciation and amortization									379,202,000		360,417,000		338,827,000
Total interest charges and financing costs									154,640,000		160,945,000		179,689,000
Income tax expense (benefit)									243,591,000		250,740,000		232,544,000
Net income (loss)	92,834,000	154,159,000	89,792,000	118,403,000	73,213,000	166,266,000	97,299,000	116,605,000	455,188,000		453,383,000		458,076,000
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									3,126,276,000		3,081,473,000		2,970,181,000
Depreciation and amortization									285,968,000		280,972,000		267,944,000
Total interest charges and financing costs									124,118,000		129,787,000		145,641,000
Income tax expense (benefit)									208,095,000		220,356,000		212,347,000
Net income (loss)									349,793,000		368,586,000		387,724,000
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									1,215,504,000		1,080,813,000		962,525,000
Depreciation and amortization									89,186,000		75,510,000		66,983,000
Total interest charges and financing costs									29,987,000		30,604,000		33,430,000
Income tax expense (benefit)									50,874,000		42,294,000		27,968,000
Net income (loss)									84,324,000		69,682,000		60,003,000
All Other
Segment Reporting Information [Line Items]
Operating revenues									41,888,000		40,754,000		36,959,000
Depreciation and amortization									4,048,000		3,935,000		3,900,000
Total interest charges and financing costs									535,000		554,000		618,000
Income tax expense (benefit)									(15,378,000)		(11,910,000)		(7,771,000)
Net income (loss)									21,071,000		15,115,000		10,349,000
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues									4,383,149,000	[1]	4,202,628,000	[1]	3,969,293,000	[1]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									3,125,937,000	[1]	3,081,171,000	[1]	2,969,899,000	[1]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									1,215,324,000	[1]	1,080,703,000	[1]	962,435,000	[1]
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues									41,888,000	[1]	40,754,000	[1]	36,959,000	[1]
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues									(519,000)		(412,000)		(372,000)
Depreciation and amortization									0		0		0
Total interest charges and financing costs									0		0		0
Income tax expense (benefit)									0		0		0
Net income (loss)									0		0		0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									339,000		302,000		282,000
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									180,000		110,000		90,000
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues									$ 0		$ 0		$ 0

[1] Operating revenues include $14 million, $13 million and $14 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012, respectively. See Note 16 for further discussion of related party transactions by reportable segment.

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Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2014 Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (in hundredths)	77.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	2,063

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 3,890,229	$ 3,872,643
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,328,968	$ 4,059,661

XML

Regulatory Assets and Liabilities, Regulatory Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 120,120,000		$ 150,163,000
Regulatory Asset, Noncurrent	903,973,000		826,037,000
Past expenditures not currently earning a return	104,000,000		136,000,000
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current	32,195,000	[1]	45,504,000	[1]
Regulatory Asset, Noncurrent	500,889,000	[1]	447,752,000	[1]
Regulatory asset, remaining amortization period	Various
Non Qualified Pension Plan
Regulatory Assets [Line Items]
Regulatory Asset, Current	400,000		400,000
Regulatory Asset	4,500,000		4,100,000
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current	0		0
Regulatory Asset, Noncurrent	141,214,000		116,477,000
Regulatory asset, remaining amortization period	Plant lives
Contract Valuation Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	8,901,000	[2]	3,620,000	[2]
Regulatory Asset, Noncurrent	12,999,000	[2]	16,474,000	[2]
Regulatory asset, remaining amortization period	Term of related contract
Depreciation Differences
Regulatory Assets [Line Items]
Regulatory Asset, Current	10,700,000		10,917,000
Regulatory Asset, Noncurrent	104,743,000		95,844,000
Regulatory asset, remaining amortization period, minimum	1 year
Regulatory asset, remaining amortization period, maximum	17 years
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	0	[3]	0	[3]
Regulatory Asset, Noncurrent	46,213,000	[3]	39,986,000	[3]
Regulatory asset, remaining amortization period	Plant lives
Conservation Programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	10,198,000	[4]	13,883,000	[4]
Regulatory Asset, Noncurrent	10,906,000	[4]	19,430,000	[4]
Regulatory asset, remaining amortization period, minimum	1 year
Regulatory asset, remaining amortization period, maximum	5 years
Gas Pipeline Inspection Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current	5,416,000		5,416,000
Regulatory Asset, Noncurrent	3,611,000		14,978,000
Regulatory asset, remaining amortization period, minimum	1 year
Regulatory asset, remaining amortization period, maximum	4 years
Renewable Resources and Environmental Initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current	0		22,325,000
Regulatory Asset, Noncurrent	0		0
Regulatory asset, remaining amortization period, minimum	1 year
Regulatory asset, remaining amortization period, maximum	2 years
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory Asset, Current	858,000		0
Regulatory Asset, Noncurrent	29,596,000		30,069,000
Regulatory asset, remaining amortization period	Term of related contract
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current	1,426,000		1,572,000
Regulatory Asset, Noncurrent	8,378,000		9,804,000
Regulatory asset, remaining amortization period	Term of related debt
Recoverable Purchased Natural Gas and Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current	18,410,000		18,022,000
Regulatory Asset, Noncurrent	0		0
Regulatory asset, remaining amortization period	Less than one year
Property Tax
Regulatory Assets [Line Items]
Regulatory Asset, Current	28,024,000		18,427,000
Regulatory Asset, Noncurrent	31,429,000		30,626,000
Regulatory asset, remaining amortization period, minimum	1 year
Regulatory asset, remaining amortization period, maximum	3 years
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Asset, Current	3,992,000		10,477,000
Regulatory Asset, Noncurrent	$ 13,995,000		$ 4,597,000
Regulatory asset, remaining amortization period	Various

[1] Includes $4.5 million and $4.1 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2014 and 2013, respectively.

[2] Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

[3] Includes amounts recorded for future recovery of AROs.

[4] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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Commitments and Contingencies, Variable Interest Entities (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013 MW
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,802	1,441
Maximum [Member]
Purchased Power Agreements [Abstract]
Purchase Power Agreement Duration, Maximum	2032

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Regulatory Assets and Liabilities, Regulatory Liabilities (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 134,459		$ 79,499
Regulatory Liability, Noncurrent	464,421		424,690
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory Liability, Noncurrent	366,359		359,387
Regulatory Noncurrent Liability, Amortization Period	Plant lives
Deferred Electric, Gas, and Steam Production Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	24,035		33,247
Regulatory Liability, Noncurrent	0		0
Regulatory Noncurrent Liability, Amortization Period	Less than one year
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory Liability, Noncurrent	22,225		24,038
Regulatory Noncurrent Liability, Amortization Period	Various
Deferred Income Tax Adjustment
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory Liability, Noncurrent	18,672		18,770
Regulatory Noncurrent Liability, Amortization Period	Various
Conservation Programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	32,226	[1]	12,188	[1]
Regulatory Liability, Noncurrent	0	[1]	0	[1]
Regulatory Noncurrent Liability, Amortization Period	Less than one year
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	3,308		0
Regulatory Liability, Noncurrent	10,376		1,412
Regulatory Noncurrent Liability, Amortization Period	Various
Low Income Discount Program
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	1,680		4,084
Regulatory Liability, Noncurrent	0		0
Regulatory Noncurrent Liability, Amortization Period	Less than one year
Gain From Asset Sales
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	316		1,687
Regulatory Liability, Noncurrent	4		368
Regulatory liability remaining amortization period, minimum	1 year
Regulatory liability remaining amortization period, maximum	3 years
PSCo Earnings Test
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	57,127		22,892
Regulatory Liability, Noncurrent	42,819		19,203
Regulatory liability remaining amortization period, minimum	1 year
Regulatory liability remaining amortization period, maximum	2 years
Gas Pipeline Inspection Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	13,970		0
Regulatory Liability, Noncurrent	642		0
Regulatory liability remaining amortization period, minimum	1 year
Regulatory liability remaining amortization period, maximum	4 years
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	1,797		5,401
Regulatory Liability, Noncurrent	$ 3,324		$ 1,512
Regulatory Noncurrent Liability, Amortization Period	Various

[1] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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Rate Matters (Details) (USD $)	12 Months Ended			1 Months Ended	12 Months Ended	1 Months Ended						12 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2010	Oct. 31, 2014	Jun. 30, 2012	Apr. 30, 2012	Aug. 31, 2013	Nov. 30, 2014	Jul. 31, 2014	Dec. 31, 2011	Jan. 23, 2015
Rate Matters [Abstract]
Regulatory Liability, Noncurrent	$ 464,421,000	$ 424,690,000		$ 464,421,000
Pretax charge for project costs	0	0	10,666,000
PSCo [Member] | CPUC Proceeding - Colorado 2014 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount	136,000,000
Public Utilities, Requested Rate Increase (Decrease), Percentage	4.83%
Public Utilities, Requested Return on Equity, Percentage	10.35%
Public Utilities, Requested Rate Base, Amount	6,390,000,000
Public Utilities, Requested Equity Capital Structure, Percentage	56.00%
Public Utilities, Rider costs to be recovered through base rates, amount	19,900,000
PSCo [Member] | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount	136,000,000
Public Utilities, Portion of requested rate increase (decrease) attributable to CACJA recovery	100,900,000
Public Utilities, Portion of requested rate increase (decrease) attributable to CACJA recovery, Amended	98,700,000
Public Utilities, Rider costs to be recovered through base rates, amount	19,900,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				107,200,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage				3.79%
Public Utilities, Requested Return on Equity, Revised, Percentage				10.25%
Public Utilities, Revenue deficiency based on a forecast test year	155,900,000
Public Utilities, Adjustment to requested rate increase (decrease) related to return on equity				(6,200,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to change in capital structure				0
Public Utilities, Adjustment to requested rate increase (decrease) related to rate base adjustments				0
Public Utilities, Adjustment to requested rate increase (decrease) related to adjusting to a historic test year				0
Public Utilities, Adjustment to requested rate increase (decrease) related to use of a 13-month average rate base				0
Public Utilities, Adjustment to requested rate increase (decrease) related to rate base adjustments for known and measurable plant				0
Public Utilities, Adjustment to requested rate increase (decrease) related to operations and maintenance expenses				0
Public Utilities, Adjustment to requested rate increase (decrease) related to depreciation expense				0
Public Utilities, Adjustment to requested rate increase (decrease) related to property taxes				(5,300,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to removing CACJA rider from base rates				(98,700,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to an updated sales forecast				(15,200,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to prepaid pension amortization				0
Public Utilities, Adjustment to requested rate increase (decrease) related to non-specified settlement adjustments				0
Public Utilities, Adjustment to requested rate increase (decrease) related to other costs				(2,100,000)
Public Utilities, Net recommended base rate increase (decrease)				28,400,000
Public Utilities, Revenue impact of CACJA rider mechanism				98,700,000
Public Utilities, Revenue impact of 2015 TCA rider mechanism				0
Public Utilities, Rider costs not to be recovered through base rates, amount				(19,900,000)
Public Utilities, Total recommended revenue increase (decrease)				107,200,000
PSCo [Member] | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2016
Rate Matters [Abstract]
Public Utilities, Requested increase (decrease) to rider revenue	34,200,000
PSCo [Member] | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2017
Rate Matters [Abstract]
Public Utilities, Requested increase (decrease) to rider revenue	29,900,000
PSCo [Member] | CPUC Proceeding - Manufacturer's Sales Tax Refund
Rate Matters [Abstract]
Public Utilities, Maximum annual amount of property taxes not subject to deferral	76,700,000
Public Utilities, Reduction in property tax deferral	10,000,000
PSCo [Member] | CPUC Proceeding - Annual Electric Earnings Test
Rate Matters [Abstract]
Public Utilities, Return on equity threshold for earnings sharing	10.00%
PSCo [Member] | CPUC Proceeding - 2014 Electric Earnings Test
Rate Matters [Abstract]
Regulatory Liability, Noncurrent	74,000,000			74,000,000
PSCo [Member] | CPUC Proceeding - Smart Grid City Cost Recovery
Rate Matters [Abstract]
Public Utilities, Estimated cost of project					45,000,000
Public Utilities, Annual operating and maintenance costs associated with project					4,000,000
Pretax charge for project costs			10,700,000
PSCo [Member] | CPUC Proceeding - Demand Side Management Cost Adjustment
Rate Matters [Abstract]
Public Utilities, Incentive award upon achieving savings goal	5,000,000
Public Utilities, Percentage of net economic benefits on which incentive is earned	5.00%
Public Utilities, Maximum annual incentive	30,000,000
PSCo [Member] | CPUC Proceeding - Demand Side Management Cost Adjustment, 2015
Rate Matters [Abstract]
Public Utilities, Proposed electric demand side management budget						81,600,000
Public Utilities, Proposed gas demand side management budget						13,100,000
PSCo [Member] | CPUC Proceeding - Demand Side Management Cost Adjustment, 2016
Rate Matters [Abstract]
Public Utilities, Proposed electric demand side management budget						78,700,000
Public Utilities, Proposed gas demand side management budget						13,600,000
PSCo [Member] | CPUC Proceeding - Renewable Energy Credit Sharing
Rate Matters [Abstract]
Public Utilities, Customers share of margins credited against RESA regulatory asset balance	600,000	21,700,000
Public Utilities, Cumulative credit against RESA regulatory asset balance	105,100,000	104,500,000		105,100,000
PSCo [Member] | FERC Proceeding - Transmission Formula Rate Cases
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount								2,000,000
Public Utilities, Requested Return on Equity, Percentage							10.25%
Public Utilities, Return on equity requested by third parties, Percentage							9.15%
PSCo [Member] | FERC Proceeding - Production Formula Rate ROE Complaint
Rate Matters [Abstract]
Public Utilities, Return on equity requested by third parties, Percentage									9.04%
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2014 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Return on equity recommended by third parties										9.11%
Public Utilities, Equity capital structure recommended by third parties										51.24%
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015
Rate Matters [Abstract]
Public Utilities, Adjustment to requested rate increase (decrease) related to return on equity										(69,100,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to change in capital structure										(20,900,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to rate base adjustments										(20,800,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to adjusting to a historic test year										(82,500,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to use of a 13-month average rate base										(26,100,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to rate base adjustments for known and measurable plant										21,900,000
Public Utilities, Adjustment to requested rate increase (decrease) related to operations and maintenance expenses										(7,200,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to depreciation expense										0
Public Utilities, Adjustment to requested rate increase (decrease) related to property taxes										0
Public Utilities, Adjustment to requested rate increase (decrease) related to removing CACJA rider from base rates										(62,400,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to an updated sales forecast										0
Public Utilities, Adjustment to requested rate increase (decrease) related to prepaid pension amortization										0
Public Utilities, Adjustment to requested rate increase (decrease) related to non-specified settlement adjustments										0
Public Utilities, Adjustment to requested rate increase (decrease) related to other costs										100,000
Public Utilities, Net recommended base rate increase (decrease)										(111,100,000)
Public Utilities, Revenue impact of CACJA rider mechanism										54,200,000
Public Utilities, Revenue impact of 2015 TCA rider mechanism										0
Public Utilities, Rider costs not to be recovered through base rates, amount										(19,900,000)
Public Utilities, Total recommended revenue increase (decrease)										(76,800,000)
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - 2013 Electric Earnings Test
Rate Matters [Abstract]
Public Utilities, Refund Approved, Amount											45,700,000
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Smart Grid City Cost Recovery
Rate Matters [Abstract]
Public Utilities, Cost of project allowed for recovery												28,000,000
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Demand Side Management Cost Adjustment, 2014
Rate Matters [Abstract]
Public Utilities, Maximum savings goal (in MWh)	384,000
Public Utilities, Electric demand side management budget	87,800,000
Public Utilities, Gas demand side management budget	12,300,000
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Demand Side Management Cost Adjustment, 2015
Rate Matters [Abstract]
Public Utilities, Maximum savings goal (in MWh)	400,000
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Renewable Energy Credit Sharing
Rate Matters [Abstract]
Public Utilities, Margin threshold determining percentage of margin sharing			20,000,000
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Renewable Energy Credit Sharing | Shareholders
Rate Matters [Abstract]
Public Utilities, Ultimate margin sharing associated with stand alone REC transactions												10.00%
Public Utilities, Percentage of margin on hybrid REC approved for first 20 million of margins			20.00%
Public Utilities, Percentage of margin on hybrid REC approved for margins in excess of 20 million			10.00%
PSCo [Member] | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Renewable Energy Credit Sharing | Customers
Rate Matters [Abstract]
Public Utilities, Ultimate margin sharing associated with stand alone REC transactions												90.00%
Public Utilities, Percentage of margin on hybrid REC approved for first 20 million of margins			80.00%
Public Utilities, Percentage of margin on hybrid REC approved for margins in excess of 20 million			90.00%
PSCo [Member] | Office of Consumer Counsel (OCC) | CPUC Proceeding - Colorado 2014 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Return on equity recommended by third parties										9.10%
Public Utilities, Equity capital structure recommended by third parties										52.70%
PSCo [Member] | Office of Consumer Counsel (OCC) | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015
Rate Matters [Abstract]
Public Utilities, Adjustment to requested rate increase (decrease) related to return on equity										(66,500,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to change in capital structure										(23,700,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to rate base adjustments										2,300,000
Public Utilities, Adjustment to requested rate increase (decrease) related to adjusting to a historic test year										(82,500,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to use of a 13-month average rate base										(22,000,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to rate base adjustments for known and measurable plant										0
Public Utilities, Adjustment to requested rate increase (decrease) related to operations and maintenance expenses										(16,600,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to depreciation expense										(3,800,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to property taxes										(12,100,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to removing CACJA rider from base rates										0
Public Utilities, Adjustment to requested rate increase (decrease) related to an updated sales forecast										0
Public Utilities, Adjustment to requested rate increase (decrease) related to prepaid pension amortization										0
Public Utilities, Adjustment to requested rate increase (decrease) related to non-specified settlement adjustments										0
Public Utilities, Adjustment to requested rate increase (decrease) related to other costs										100,000
Public Utilities, Net recommended base rate increase (decrease)										(68,900,000)
Public Utilities, Revenue impact of CACJA rider mechanism										0
Public Utilities, Revenue impact of 2015 TCA rider mechanism										0
Public Utilities, Rider costs not to be recovered through base rates, amount										(19,900,000)
Public Utilities, Total recommended revenue increase (decrease)										(88,800,000)
PSCo [Member] | Federal Energy Regulatory Commission (FERC) | FERC Proceeding - Transmission Formula Rate Cases
Rate Matters [Abstract]
Public Utilities, Approved Return on Equity, Percentage						9.72%
PSCo [Member] | Federal Energy Regulatory Commission (FERC) | FERC Proceeding - Production Formula Rate ROE Complaint
Rate Matters [Abstract]
Public Utilities, Approved Return on Equity, Percentage						9.72%
Subsequent Event | PSCo [Member] | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015
Rate Matters [Abstract]
Public Utilities, Estimated expense deferral from settlement													3,100,000
Subsequent Event | PSCo [Member] | Parties to Settlement Agreement | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015
Rate Matters [Abstract]
Public Utilities, Requested Equity Capital Structure, Percentage													56.00%
Public Utilities, Settlement Agreement, Requested Rate Increase (Decrease), Amount													53,300,000
Public Utilities, Settlement Agreement, Requested Rate Increase (Decrease), Percentage													1.87%
Public Utilities, Settlement Agreement, Requested Return on Equity, Percentage													9.83%
Public Utilities, Adjustment to requested rate increase (decrease) related to return on equity													(27,900,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to change in capital structure													0
Public Utilities, Adjustment to requested rate increase (decrease) related to rate base adjustments													0
Public Utilities, Adjustment to requested rate increase (decrease) related to adjusting to a historic test year													(23,900,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to use of a 13-month average rate base													0
Public Utilities, Adjustment to requested rate increase (decrease) related to rate base adjustments for known and measurable plant													0
Public Utilities, Adjustment to requested rate increase (decrease) related to operations and maintenance expenses													0
Public Utilities, Adjustment to requested rate increase (decrease) related to depreciation expense													0
Public Utilities, Adjustment to requested rate increase (decrease) related to property taxes													(5,300,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to removing CACJA rider from base rates													(98,700,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to an updated sales forecast													(15,200,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to prepaid pension amortization													9,500,000
Public Utilities, Adjustment to requested rate increase (decrease) related to non-specified settlement adjustments													(31,700,000)
Public Utilities, Adjustment to requested rate increase (decrease) related to other costs													(2,100,000)
Public Utilities, Net recommended base rate increase (decrease)													(39,400,000)
Public Utilities, Revenue impact of CACJA rider mechanism													97,000,000
Public Utilities, Revenue impact of 2015 TCA rider mechanism													15,600,000
Public Utilities, Rider costs not to be recovered through base rates, amount													(19,900,000)
Public Utilities, Total recommended revenue increase (decrease)													$ 53,300,000
Subsequent Event | PSCo [Member] | Parties to Settlement Agreement | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015 | Shareholders
Rate Matters [Abstract]
Public Utilities, Percentage share in earnings for ROE recognized within earnings thresholds													50.00%
Subsequent Event | PSCo [Member] | Parties to Settlement Agreement | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015 | Customers
Rate Matters [Abstract]
Public Utilities, Percentage share in earnings for ROE recognized within earnings thresholds													50.00%
Minimum | PSCo [Member] | FERC Proceeding - Production Formula Rate ROE Complaint
Rate Matters [Abstract]
Public Utilities, Base return on equity charged to customers through production formula rates, Percentage									10.10%
Minimum | Subsequent Event | PSCo [Member] | Parties to Settlement Agreement | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015
Rate Matters [Abstract]
Public Utilities, Return on equity threshold for earnings sharing													9.84%
Maximum [Member] | PSCo [Member] | FERC Proceeding - Production Formula Rate ROE Complaint
Rate Matters [Abstract]
Public Utilities, Base return on equity charged to customers through production formula rates, Percentage									10.40%
Maximum [Member] | Subsequent Event | PSCo [Member] | Parties to Settlement Agreement | CPUC Proceeding - Colorado 2014 Electric Rate Case, Electric Rates 2015
Rate Matters [Abstract]
Public Utilities, Return on equity threshold for earnings sharing													10.48%

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Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$ (23,338)	$ (22,871)	$ (12,377)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(72)	9	(9,311)
After-tax net realized gains on derivative transactions reclassified into earnings	(468)	(476)	(1,183)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ (23,878)	$ (23,338)	$ (22,871)

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Other Comprehensive Income

12 Months Ended

Dec. 31, 2014

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2014			Year Ended Dec. 31, 2013
Accumulated other comprehensive loss at Jan. 1	$	(23,338	)	$	(22,871	)
Other comprehensive (loss) income before reclassifications	(72		)	9
Gains reclassified from net accumulated other comprehensive loss	(468		)	(476		)
Net current period other comprehensive loss	(540		)	(467		)
Accumulated other comprehensive loss at Dec. 31	$	(23,878	)	$	(23,338	)

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2014				Year Ended Dec. 31, 2013
Gains on cash flow hedges:
Interest rate derivatives	$	(730	)	(a)	$	(730	)	(a)
Vehicle fuel derivatives	(25		)	(b)	(40		)	(b)
Total, pre-tax	(755		)		(770		)
Tax expense	287				294
Total amounts reclassified, net of tax	$	(468	)		$	(476	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Short-term Debt [Line Items]
Amount outstanding at period end	$ 382,000,000	$ 382,000,000	$ 0
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000,000	250,000,000	250,000,000	250,000,000
Amount outstanding at period end	0	0	0	0
Average amount outstanding	1,000,000	4,200,000	0	0
Maximum amount outstanding	21,000,000	97,000,000	12,000,000	8,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.28%	0.25%	0.36%	0.33%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	700,000,000	700,000,000	700,000,000	700,000,000
Amount outstanding at period end	382,000,000	382,000,000	0	154,000,000
Average amount outstanding	292,000,000	167,000,000	38,000,000	8,000,000
Maximum amount outstanding	$ 393,000,000	$ 393,000,000	$ 332,000,000	$ 165,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.37%	0.31%	0.34%	0.33%
Weighted average interest rate at period end (percentage)	0.65%	0.65%		0.35%

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Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2014

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2014			Year Ended Dec. 31, 2013
Accumulated other comprehensive loss at Jan. 1	$	(23,338	)	$	(22,871	)
Other comprehensive (loss) income before reclassifications	(72		)	9
Gains reclassified from net accumulated other comprehensive loss	(468		)	(476		)
Net current period other comprehensive loss	(540		)	(467		)
Accumulated other comprehensive loss at Dec. 31	$	(23,878	)	$	(23,338	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2014				Year Ended Dec. 31, 2013
Gains on cash flow hedges:
Interest rate derivatives	$	(730	)	(a)	$	(730	)	(a)
Vehicle fuel derivatives	(25		)	(b)	(40		)	(b)
Total, pre-tax	(755		)		(770		)
Tax expense	287				294
Total amounts reclassified, net of tax	$	(468	)		$	(476	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Contract [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Transfers into Level 3	$ 0	$ 0	$ 0
Transfers out of Level 3	$ 0	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2014

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 Dec. 31:

(Amounts in Thousands)(a)(b)	2014	2013
MWh of electricity	—	326
MMBtu of natural gas	735	6,398
Gallons of vehicle fuel	127	217

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

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

Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:

(Thousands of Dollars)	2014			2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,338	)	$	(22,871	)	$	(12,377	)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(72		)	9			(9,311		)
After-tax net realized gains on derivative transactions reclassified into earnings	(468		)	(476		)	(1,183		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23,878	)	$	(23,338	)	$	(22,871	)

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 years ended Dec. 31, 2014, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)				Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—	$	(730	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(115		)	—		(25		)	(b)	—				—
Total	$	(115	)	$	—	$	(755	)		$	—			$	—
Other derivative instruments
Natural gas commodity	$	—		$	451	$	—			$	(4,631	)	(e)	$	(9,850	)	(e)
Total	$	—		$	451	$	—			$	(4,631	)		$	(9,850	)

	Year Ended Dec. 31, 2013
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains)Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	(730	)	(a)	$	—		$	—
Vehicle fuel and other commodity	14		—			(40		)	(b)	—			—
Total	$	14	$	—		$	(770	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—	$	(4,001	)	$	—			$	4,340	(e)	$	5,850	(d)
Total	$	—	$	(4,001	)	$	—			$	4,340		$	5,850

	Year Ended Dec. 31, 2012
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(15,082	)	$	—	$	(1,819	)	(a)	$	—		$	—
Vehicle fuel and other commodity	63			—		(89		)	(b)	—			—
Total	$	(15,019	)	$	—	$	(1,908	)		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—		$	2		(c)
Natural gas commodity	—			7,727		—				61,820		(e)	(137		)	(d)
Total	$	—		$	7,727	$	—			$	61,820		$	(135	)

^(a)  Amounts are recorded to interest charges.

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

^(e)  Amounts for the year ended Dec. 31, 2012 included $5.0 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.  Such losses for the years ended Dec. 31, 2014 and 2013 were immaterial.  The remaining settlement losses for the years ended Dec. 31, 2014, 2013 and 2012 relate to natural gas operations and are recorded to cost of natural gas sold and transported.  These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

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

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

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

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, PSCo qualified these contracts under the normal purchase exception.  Based 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 Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:

	Dec. 31, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	40	$	—	$	40	$	—		$	40
Other derivative instruments:
Commodity trading	—		2,756		—		2,756		(1,276		)	1,480
Natural gas commodity	—		3,341		—		3,341		—			3,341
Total current derivative assets	$	—	$	6,137	$	—	$	6,137	$	(1,276	)	4,861
PPAs (a)												1,715
Current derivative instruments												$	6,576
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	13	$	—	$	13	$	—		$	13
Total noncurrent derivative assets	$	—	$	13	$	—	$	13	$	—		13
PPAs (a)												6,892
Noncurrent derivative instruments												$	6,905
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	$	1,399
Total current derivative liabilities	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	1,399
PPAs (a)												5,335
Current derivative instruments												$	6,734
Noncurrent derivative liabilities
PPAs (a)												23,366
Noncurrent derivative instruments												$	23,366

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

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013.  At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Carrying Amount and Fair Value of Long-term Debt

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

	2014				2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,890,229	$	4,328,968	$	3,872,643	$	4,059,661

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Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	12 Months Ended		1 Months Ended
	Dec. 31, 2014		Oct. 31, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio	47.00%			45.00%
Direct advances on the credit facility outstanding				$ 0
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	100,000,000
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed	65.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions	15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions	75,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	1 year
Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Initiation Date			Oct. 31, 2014
Debt Instrument, Term			5 years
Credit Facility	700,000,000	[1]
Drawn	388,400,000	[2]
Available	311,600,000
Direct advances on the credit facility outstanding	$ 0
Minimum | Credit Facility
Line of Credit Facility [Line Items]
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.075%
Maximum [Member] | Credit Facility
Line of Credit Facility [Line Items]
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.275%
Eurodollar [Member] | Minimum | Credit Facility
Line of Credit Facility [Line Items]
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.875%
Eurodollar [Member] | Maximum [Member] | Credit Facility
Line of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.75%

[1] These credit facilities have been amended to extend the maturity to October 2019.

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

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Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (Postretirement Benefit Plan, USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 508,971,000		$ 599,831,000
Service cost	1,915,000		2,564,000		2,825,000
Interest cost	23,704,000		22,210,000		24,527,000
Medicare subsidy reimbursements	1,753,000		923,000
Plan amendments	0		(14,571,000)
Plan participants' contributions	4,625,000		4,589,000
Actuarial (gain) loss	(63,130,000)		(76,889,000)
Benefit payments	(34,085,000)		(29,686,000)
Obligation at Dec. 31	443,753,000		508,971,000		599,831,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	438,193,000		425,917,000
Actual return (loss) on plan assets	11,060,000		30,390,000
Plan participants' contributions	4,625,000		4,589,000
Employer contributions	5,489,000		6,983,000
Benefit payments	(34,085,000)		(29,686,000)
Fair value of plan assets at Dec. 31	425,282,000		438,193,000		425,917,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	(18,471,000)	[1]	(70,778,000)	[1]
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	56,823,000		107,232,000
Prior service (credit) cost	(40,189,000)		(46,436,000)
Total	16,634,000		60,796,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets	0		8,798,000
Noncurrent regulatory assets	16,634,000		51,998,000
Total	16,634,000		60,796,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Measurement date	12/31/2014		12/31/2013
Discount rate for year-end valuation (in hundredths)	4.08%		4.82%
Mortality table	RP 2014		RP 2000
Health care costs trend rate - initial (in hundredths)	6.50%		7.00%
Ultimate health care trend assumption rate (in hundredths)	4.50%		4.50%
Period until ultimate trend rate is reached (in years)	4 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO	45,581,000
One-percent decrease in APBO	(38,371,000)
One-percent increase in service and interest components	3,028,000
One-percent decrease in service and interest components	(2,488,000)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	5,500,000		7,000,000		27,500,000
Expected contribution to postretirement health care plans during 2015	0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	1,915,000		2,564,000		2,825,000
Interest cost	23,704,000		22,210,000		24,527,000
Expected return on plan assets	(30,214,000)		(29,227,000)		(25,056,000)
Amortization of transition obligation	0		785,000		11,004,000
Amortization of prior service (credit) cost	(6,247,000)		(7,666,000)		(5,150,000)
Amortization of net loss	6,434,000		13,699,000		10,930,000
Net periodic benefit cost	(4,408,000)		2,365,000		19,080,000
Additional cost recognized due to effects of regulation	0		0		3,891,000
Net benefit cost recognized for financial reporting	(4,408,000)		2,365,000		22,971,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (in hundredths)	4.82%		4.10%		5.00%
Expected average long-term rate of return on assets (in hundredths)	7.18%		7.11%		6.75%
Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	17,100,000		17,600,000		47,100,000
Expected contribution to postretirement health care plans during 2015	$ 12,800,000

[1] Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.

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Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Pension Plan Assets (Details) (Pension Plans, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	$ 1,103,865	$ 1,067,057		$ 1,055,308
Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	64,578	82,991		94,157
Net realized gains (losses)	9,675	6,204		6,937
Net unrealized gains (losses)	(4,601)	(258)		(7,380)
Purchases, issuances and settlements, net	(1,032)	1,967		(10,723)
Transfers in (out) of Level 3	0	(26,326)	[1]	0
Fair value of plan assets at Dec. 31	68,620	64,578		82,991
Asset-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	1,360	2,356
Asset-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		4,604		9,824
Net realized gains (losses)		0		1,175
Net unrealized gains (losses)		0		(1,597)
Purchases, issuances and settlements, net		0		(4,798)
Transfers in (out) of Level 3		(4,604)	[1]	0
Fair value of plan assets at Dec. 31	0	0		4,604
Mortgage-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	3,997	5,267		12,058
Mortgage-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		12,058		23,614
Net realized gains (losses)		0		550
Net unrealized gains (losses)		0		(625)
Purchases, issuances and settlements, net		0		(11,481)
Transfers in (out) of Level 3		(12,058)	[1]	0
Fair value of plan assets at Dec. 31	0	0		12,058
Private equity investments
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	50,210	49,022
Private equity investments | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	49,022	47,056		49,489
Net realized gains (losses)	8,495	7,074		5,206
Net unrealized gains (losses)	(4,299)	(4,027)		(7,001)
Purchases, issuances and settlements, net	(3,008)	(1,081)		(638)
Transfers in (out) of Level 3	0	0	[1]	0
Fair value of plan assets at Dec. 31	50,210	49,022		47,056
Real estate
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	18,410	15,556		19,273
Real estate | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	15,556	19,273		11,230
Net realized gains (losses)	1,180	(870)		6
Net unrealized gains (losses)	(302)	3,769		1,843
Purchases, issuances and settlements, net	1,976	3,048		6,194
Transfers in (out) of Level 3	0	(9,664)	[1]	0
Fair value of plan assets at Dec. 31	$ 18,410	$ 15,556		$ 19,273

[1] Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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Selected Balance Sheet Data (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$ 346,007	$ 351,180
Less allowance for bad debts	(23,122)	(22,505)
Accounts receivable, net	$ 322,885	$ 328,675

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Beginning Balance at Dec. 31, 2011	$ 4,305,718	$ 0	$ 3,316,386	$ 1,001,709	$ (12,377)
Balance (in shares) at Dec. 31, 2011		100
Increase (Decrease) in Stockholder's Equity
Net income	458,076			458,076
Other comprehensive income (loss)	(10,494)				(10,494)
Common dividends declared to parent	(266,848)			(266,848)
Contribution of capital by parent	99,283		99,283
Ending Balance at Dec. 31, 2012	4,585,735	0	3,415,669	1,192,937	(22,871)
Balance (in shares) at Dec. 31, 2012		100
Increase (Decrease) in Stockholder's Equity
Net income	453,383			453,383
Other comprehensive income (loss)	(467)				(467)
Common dividends declared to parent	(262,273)			(262,273)
Contribution of capital by parent	25,621		25,621
Ending Balance at Dec. 31, 2013	4,801,999	0	3,441,290	1,384,047	(23,338)
Balance (in shares) at Dec. 31, 2013	100	100
Increase (Decrease) in Stockholder's Equity
Net income	455,188			455,188
Other comprehensive income (loss)	(540)				(540)
Common dividends declared to parent	(452,306)			(452,306)
Contribution of capital by parent	81,498		81,498
Ending Balance at Dec. 31, 2014	$ 4,885,839	$ 0	$ 3,522,788	$ 1,386,929	$ (23,878)
Balance (in shares) at Dec. 31, 2014	100	100

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Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (Pension Plans, USD $)	12 Months Ended					1 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Jan. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31	$ 1,249,739,000		$ 1,134,184,000
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	1,152,836,000		1,194,371,000
Service cost	23,939,000		25,206,000		22,719,000
Interest cost	53,277,000		46,160,000		51,192,000
Transfer (to) from other plan	(13,404,000)		11,306,000
Actuarial (gain) loss	133,215,000		(49,384,000)
Benefit payments	(71,906,000)		(74,823,000)
Obligation at Dec. 31	1,277,957,000		1,152,836,000		1,194,371,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	1,067,057,000		1,055,308,000
Actual return (loss) on plan assets	84,871,000		30,684,000
Employer contributions	35,156,000		44,582,000
Transfer (to) from other plan	(11,313,000)		11,306,000
Benefit payments	(71,906,000)		(74,823,000)
Fair value of plan assets at Dec. 31	1,103,865,000		1,067,057,000		1,055,308,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	(174,092,000)	[1]	(85,779,000)	[1]
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	530,674,000		450,202,000
Prior service (credit) cost	(18,708,000)		(21,800,000)
Total	511,966,000		428,402,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets	31,774,000		36,271,000
Noncurrent regulatory assets	480,192,000		392,131,000
Total	511,966,000		428,402,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Measurement date	2014-12-31		2013-12-31
Discount rate for year-end valuation (in hundredths)	4.11%		4.75%
Expected average long-term increase in compensation level (in hundredths)	3.75%		3.75%
Mortality table	RP 2014		RP 2000
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period	35,200,000		44,600,000		41,800,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	23,939,000		25,206,000		22,719,000
Interest cost	53,277,000		46,160,000		51,192,000
Expected return on plan assets	(70,709,000)		(63,821,000)		(65,302,000)
Amortization of prior service (credit) cost	(3,092,000)		(1,064,000)		228,000
Amortization of net loss	33,892,000		43,418,000		34,332,000
Net benefit cost recognized for financial reporting	37,307,000		49,899,000		43,169,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (in hundredths)	4.75%		4.00%		5.00%
Expected average long-term increase in compensation level (in hundredths)	3.75%		3.75%		4.00%
Expected average long-term rate of return on assets (in hundredths)	6.81%		6.47%		6.65%
Allocated costs for pension plans sponsored by Xcel Energy Inc.	9,400,000		11,600,000		9,600,000
Expected average long-term rate of return on assets for next fiscal year (in hundredths)	6.81%
Number of years fair market value of plan assets is adjusted using calculated value method (in years)	5 years
Annual adjustment rate used in calculated value method (in hundredths)	20.00%
Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period	130,600,000		192,400,000		198,100,000
Number of pension plans to which contributions were made	4		4		4
Subsequent Event
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period						20,000,000
Subsequent Event | Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period						$ 90,000,000
Number of pension plans to which contributions were made						4

[1] Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Results from Operations by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2014
Operating revenues (a)	$	3,125,937	$	1,215,324	$	41,888		$	—		$	4,383,149
Intersegment revenues	339		180		—			(519		)	—
Total revenues	$	3,126,276	$	1,215,504	$	41,888		$	(519	)	$	4,383,149
Depreciation and amortization	$	285,968	$	89,186	$	4,048		$	—		$	379,202
Interest charges and financing costs	124,118		29,987		535			—			154,640
Income tax expense (benefit)	208,095		50,874		(15,378		)	—			243,591
Net Income	349,793		84,324		21,071			—			455,188

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2013
Operating revenues (a)	$	3,081,171	$	1,080,703	$	40,754		$	—		$	4,202,628
Intersegment revenues	302		110		—			(412		)	—
Total revenues	$	3,081,473	$	1,080,813	$	40,754		$	(412	)	$	4,202,628
Depreciation and amortization	$	280,972	$	75,510	$	3,935		$	—		$	360,417
Interest charges and financing costs	129,787		30,604		554			—			160,945
Income tax expense (benefit)	220,356		42,294		(11,910		)	—			250,740
Net income	368,586		69,682		15,115			—			453,383

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2012
Operating revenues (a)	$	2,969,899	$	962,435	$	36,959		$	—		$	3,969,293
Intersegment revenues	282		90		—			(372		)	—
Total revenues	$	2,970,181	$	962,525	$	36,959		$	(372	)	$	3,969,293
Depreciation and amortization	$	267,944	$	66,983	$	3,900		$	—		$	338,827
Interest charges and financing costs	145,641		33,430		618			—			179,689
Income tax expense (benefit)	212,347		27,968		(7,771		)	—			232,544
Net income	387,724		60,003		10,349			—			458,076

^(a)  Operating revenues include $14 million, $13 million and $14 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012, respectively. See Note 16 for further discussion of related party transactions by reportable segment.

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Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2014

Valuation and Qualifying Accounts [Abstract]

Schedule II, Valuation and Qualifying Accounts

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2014, 2013 AND 2012

(amounts in thousands)

			Additions
	Balance at Jan. 1		Charged to Costs and Expenses		Charged to Other Accounts(a)		Deductions from Reserves(b)		Balance at Dec. 31
Allowance for bad debts:
2014	$	22,505	$	17,005	$	6,240	$	22,628	$	23,122
2013	21,918		16,784		7,005		23,202		22,505
2012	24,698		16,323		7,648		26,751		21,918

^(a)  Recovery of amounts previously written off.

^(b)  Principally bad debts written off.

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2014
Operating revenues	$	1,203,543	$	993,704	$	1,049,111	$	1,136,791
Operating income	208,437		163,437		261,073		169,423
Net income	118,403		89,792		154,159		92,834

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
Operating revenues	$	1,117,457	$	966,429	$	1,044,300	$	1,074,442
Operating income	212,299		183,675		289,741		143,044
Net income	116,605		97,299		166,266		73,213

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Income Taxes (Details) (USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2010
Tax Increase Prevention Act of 2014 [Abstract]
Bonus depreciation rate		50.00%	50.00%
Number of years bonus depreciation was extended		1 year	1 year
American Taxpayer Relief Act of 2012 [Abstract]
Original top tax rate for dividends			20.00%
Current top tax rate for dividends			15.00%
Bonus depreciation rate		50.00%	50.00%
Number of years bonus depreciation was extended		1 year	1 year
Prescription Drug Tax Benefit and Medicare Part D [Abstract]
Income tax expense (benefit) related to retiree prescription drug benefits	$ (17,000,000)
Number of applicable provisions addressing deductibility of retiree health care costs					1
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions		1,900,000	2,500,000
Unrecognized tax benefit — Temporary tax positions		10,000,000	5,900,000
Total unrecognized tax benefit		11,900,000	8,400,000	9,600,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1		8,400,000	9,600,000	11,400,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions		3,700,000	3,900,000	1,900,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions		(700,000)	0	(1,500,000)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions		2,800,000	3,300,000	2,000,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions		(1,200,000)	(900,000)	(4,200,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities		(1,100,000)	(7,500,000)	0
Balance at Dec. 31		11,900,000	8,400,000	9,600,000
Tax Benefits Associated With Nol And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards		(3,900,000)	(7,000,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible		(1,000,000)
Amounts accrued for penalties related to unrecognized tax benefits		0	0	0
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		2.80%	3.00%	2.30%
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits		(0.10%)	0.10%	0.10%
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items		(2.10%)	(1.40%)	(0.60%)
Effective Income Tax Rate Reconciliation, Tax Credit, Percent		(0.80%)	(0.80%)	(0.60%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent		0.00%	0.00%	(2.50%)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent		0.10%	(0.30%)	0.00%
Effective Income Tax Rate Reconciliation, Percent		34.90%	35.60%	33.70%
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)		9,550,000	(52,408,000)	176,354,000
Current State and Local Tax Expense (Benefit)		2,611,000	(7,252,000)	24,502,000
Current Change In Unrecognized Tax Expense (Benefit)		6,548,000	(2,918,000)	(3,447,000)
Deferred Federal Income Tax Expense (Benefit)		208,781,000	273,916,000	38,309,000
Deferred State and Local Income Tax Expense (Benefit)		26,196,000	38,243,000	(4,424,000)
Deferred Change In Unrecognized Tax Expense (Benefit)		(7,154,000)	4,094,000	4,207,000
Deferred investment tax credits		(2,941,000)	(2,935,000)	(2,957,000)
Income Tax Expense (Benefit)		243,591,000	250,740,000	232,544,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items		254,142,000	335,580,000	41,233,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(26,649,000)	(19,616,000)	(9,574,000)
Other Comprehensive Income (Loss), Tax		330,000	289,000	6,433,000
Deferred Income Tax Expense (Benefit)		227,823,000	316,253,000	38,092,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment		2,467,260,000	2,197,685,000
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits		110,556,000	100,003,000
Deferred Tax Liabilities, Other		140,080,000	132,436,000
Deferred Tax Liabilities, Net		2,717,896,000	2,430,124,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards		143,158,000	137,043,000
Deferred Tax Assets Unbilled Revenue Fuel Costs		57,654,000	49,171,000
Deferred Tax Assets Tax credit carryforward		34,493,000	30,643,000
Deferred Tax Assets Rate Refund		43,735,000	26,943,000
Deferred Tax Assets Deferred Investment Tax Credits		13,781,000	14,905,000
Deferred Tax Assets Regulatory Liabilities		14,549,000	14,893,000
Deferred Tax Assets, Other		37,472,000	37,614,000
Deferred Tax Assets, Net of Valuation Allowance		344,842,000	311,212,000
Deferred Tax Assets, Net		2,373,054,000	2,118,912,000
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) no longer subject to audit as statute of limitations has expired		2008
Earliest year subject to examination		2009
Year(s) under examination	2010 and 2011
Tax Adjustments, Settlements, and Unusual Provisions		12,000,000
Operating Loss Carryforwards		319,500,000	315,500,000
Tax Credit Carryforward, Amount		22,300,000	19,400,000
Carryforward expiration date range, low		2021
Carryforward expiration date range, high		2034
State and Local Jurisdiction
Tax Audits [Abstract]
Earliest year subject to examination		2009
Operating Loss Carryforwards		690,100,000	664,600,000
Tax Credit Carryforward Net Of Federal Detriment		$ 12,200,000	$ 11,200,000
Carryforward expiration date range, low		2017
Carryforward expiration date range, high		2033

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Related Party Transactions

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Thousands of Dollars)	2014		2013		2012
Operating revenues:
Electric	$	9,614	$	8,136	$	9,271
Other	4,441		4,441		4,441
Operating expenses:
Purchased power	23		1,331		6,539
Other operating expenses — paid to Xcel Energy Services Inc.	454,250		375,766		316,548
Interest expense	158		132		114
Interest income	61		273		122

Accounts receivable and payable with affiliates at Dec. 31 were:

	2014				2013
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	6,706	$	18,065	$	—
NSP-Wisconsin	22		—		8		—
SPS	5,803		—		1,056		—
Other subsidiaries of Xcel Energy Inc.	45,017		40,030		7		45,902
	$	50,842	$	46,736	$	19,136	$	45,902

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Business and System of Accounts

Business and System of Accounts— PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  PSCo’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation

Principles of Consolidation— PSCo’s consolidated financial statements include its wholly-owned subsidiaries.  In the consolidation process, all intercompany transactions and balances are eliminated.  PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities.  PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.  See Note 6 for further discussion of jointly owned generation, transmission, and gas facilities and related ownership percentages.

PSCo evaluates its arrangements and contracts with other entities, including but not limited to, investments, PPAs and fuel contracts to determine if the other party is a variable interest entity, if PSCo has a variable interest and if PSCo is the primary beneficiary.  PSCo follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether PSCo is a variable interest entity’s primary beneficiary.  See Note 12 for further discussion of variable interest entities.

Use of Estimates

Use of Estimates— In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available.  Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs.  The recorded estimates are revised when better information becomes available or when actual amounts can be determined.  Those revisions can affect operating results.

Regulatory Accounting

Regulatory Accounting— PSCo accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

• Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on PSCo’s financial condition, results of operations and cash flows.  See Note 13 for further discussion of regulatory assets and liabilities.

Revenue Recognition

Revenue Recognition— Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.  PSCo presents its revenue net of any excise or other fiduciary-type taxes or fees.

PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Conservation Programs

Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems.  These programs include approximately sixteen unique DSM products for commercial and industrial customers, as well as approximately one dozen DSM products for residential customers. Each DSM product may include one or up to several hundred measures that qualify for rebates and/or incentives.

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms.  The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals.  PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Property, Plant and Equipment and Depreciation

Property, Plant and Equipment and Depreciation— Property, plant and equipment is stated at original cost.  The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC.  The cost of plant retired is charged to accumulated depreciation and amortization.  Amounts recovered in rates for future removal costs are recorded as regulatory liabilities.  Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

PSCo records depreciation expense related to its plant using the straight-line method over the plant’s useful life.  Actuarial life studies are performed and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.7, 2.8 and 2.6 percent for the years ended Dec. 31, 2014, 2013 and 2012, respectively.

Leases

Leases — PSCo evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 12 for further discussion of leases.

AFUDC

AFUDC— AFUDC represents the cost of capital used to finance utility construction activity.  AFUDC is computed by applying a composite financing rate to qualified CWIP.  The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital).  AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates.

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases, including certain generation and transmission projects, the CPUC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.  In other cases, the CPUC has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.

Asset Retirement Obligations

AROs— PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. PSCo also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 12 for further discussion of AROs.

Income Taxes

Income Taxes— PSCo accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements.  PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.  In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property.  Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.

PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  PSCo recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.  Recognition of changes in uncertain tax positions are reflected as a component of income tax.

PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as combined or separate state income tax returns.  Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings.  Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 7 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments

Types of and Accounting for Derivative Instruments— PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, and commodity trading activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.  PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customer, see Note 10.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge).  Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

PSCo evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

See Note 10 for further discussion of PSCo’s risk management and derivative activities.

Commodity Trading Operations

Commodity Trading Operations— All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.  See Note 10 for further discussion.

Fair Value Measurements

Fair Value Measurements— PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value.  See Note 10 for further discussion.

Cash and Cash Equivalents

Cash and Cash Equivalents— PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts

Accounts Receivable and Allowance for Bad Debts— Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

Inventory

Inventory— All inventory is recorded at average cost.

Renewable Energy Credits

RECs — RECs aremarketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources.  RECs are awarded upon delivery of the associated energy and can be bought and sold.  RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced.  PSCo acquires RECs from the generation or purchase of renewable power.

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost.  The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.  As a result of state regulatory orders, PSCo records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.  The sales of RECs for trading purposes are recorded in electric utility operating revenues, net of the cost of the RECs, transaction costs, and amounts credited to customers under margin-sharing mechanisms.

Emission Allowances

Emission Allowances — Emission allowances, including the annual SO₂ and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees.  PSCo follows the inventory accounting model for all emission allowances.  Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

Environmental Costs

Environmental Costs— Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the liability can be reasonably estimated.  Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed.  If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 12 for further discussion of environmental costs.

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 8 for further discussion of benefit plans and other postretirement benefits.

Guarantees

Guarantees — PSCo recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee.

Subsequent Events

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2014 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

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Selected Balance Sheet Data (Tables)

12 Months Ended

Dec. 31, 2014

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	346,007		$	351,180
Less allowance for bad debts	(23,122		)	(22,505		)
	$	322,885		$	328,675

Inventories

(Thousands of Dollars)	Dec. 31, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	55,491	$	53,127
Fuel	80,963		86,062
Natural gas	102,525		98,818
	$	238,979	$	238,007

Property, Plant and Equipment, Net

(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	10,927,867		$	10,177,056
Natural gas plant	3,210,242			2,757,605
Common and other property	827,708			762,916
Plant to be retired (a)	71,534			101,279
Construction work in progress	828,620			952,469
Total property, plant and equipment	15,865,971			14,751,325
Less accumulated depreciation	(4,239,015		)	(4,008,928		)
	$	11,626,956		$	10,742,397

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

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Capitalization
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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Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2014

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At Dec. 31, 2014, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	388.4	$	311.6

^(a)  These credit facilities have been amended to extend the maturity to October 2019.

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

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2014
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	1
Maximum amount outstanding	21
Weighted average interest rate, computed on a daily basis	0.28		%
Weighted average interest rate at period end	N/A

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	4.2			0.1			0.3
Maximum amount outstanding	97			12			8
Weighted average interest rate, computed on a daily basis	0.25		%	0.36		%	0.33		%
Weighted average interest rate at period end	N/A			N/A			N/A

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2014
Borrowing limit	$	700
Amount outstanding at period end	382
Average amount outstanding	292
Maximum amount outstanding	393
Weighted average interest rate, computed on a daily basis	0.37		%
Weighted average interest rate at period end	0.65

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	382			—			154
Average amount outstanding	167			38			8
Maximum amount outstanding	393			332			165
Weighted average interest rate, computed on a daily basis	0.31		%	0.34		%	0.33		%
Weighted average interest rate at period end	0.65			N/A			0.35

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Commitments and Contingencies, Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 60,398		$ 43,751
Liabilities recognized	21,864		575
Liabilities settled	0		(941)
Accretion	3,701		2,276
Cash Flow Revisions	139,333		14,737
Ending balance	225,296	[1]	60,398
Electric Plant Steam and Other Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	23,914		19,734
Liabilities recognized	747		0
Liabilities settled	0		(941)
Accretion	1,597		1,247
Cash Flow Revisions	10,598		3,874
Ending balance	36,856	[1]	23,914
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	29,234		12,919
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	1,897		684
Cash Flow Revisions	30,754		15,631
Ending balance	61,885	[1]	29,234
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	2,953		2,928
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	22		25
Cash Flow Revisions	(880)		0
Ending balance	2,095	[1]	2,953
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,176		6,392
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	43		178
Cash Flow Revisions	(37)		(5,394)
Ending balance	1,182	[1]	1,176
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,017		627
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	41		60
Cash Flow Revisions	92		330
Ending balance	1,150	[1]	1,017
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	788		842
Liabilities recognized	18,252		0
Liabilities settled	0		0
Accretion	50		53
Cash Flow Revisions	98,384		(107)
Ending balance	117,474	[1]	788
Natural Gas Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	575		0
Liabilities recognized	2,865		575
Liabilities settled	0		0
Accretion	24		0
Cash Flow Revisions	422		0
Ending balance	3,886	[1]	575
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	741		309
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	27		29
Cash Flow Revisions	0		403
Ending balance	$ 768	[1]	$ 741

[1] There were no ARO liabilities settled during the year ended Dec. 31, 2014.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Estimated Minimum Purchases Under Fuel Contracts [Abstract]

The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2014, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2015	$	321.0	$	298.3	$	136.3
2016	261.3		153.0		79.6
2017	193.6		158.8		54.8
2018	42.4		212.3		53.9
2019	43.2		221.7		51.8
Thereafter	384.0		732.7		831.1
Total	$	1,245.5	$	1,776.8	$	1,207.5

Schedule of Long-term Contracts for Purchase of Electric Power [Table Text Block]

Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $69.5 million, $72.7 million and $119.5 million in 2014, 2013 and 2012, respectively. At Dec. 31, 2014, the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:

(Millions of Dollars)	Capacity		Energy (a)
2015	$	82.9	$	49.5
2016	58.4		22.5
2017	35.0		4.0
2018	27.8		—
2019	19.0		—
Thereafter	47.6		—
Total	$	270.7	$	76.0

^(a)  Excludes contingent energy payments for renewable energy PPAs.

Schedule of Capital Leased Assets [Table Text Block]

PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $7.2 million, $6.3 million, and $5.7 million for 2014, 2013 and 2012, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(49.0		)	(41.8		)
Total property held under capital leases, net	$	172.2		$	179.4

Schedule Of Future Minimum Rental Payments For Operating And Capital Leases [Table Text Block]

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are:

(Millions of Dollars)	Operating Leases		PPA (a) (b) Operating Leases		Total Operating Leases		Capital Leases
2015	$	14.5	$	113.8	$	128.3	$	30.5
2016	11.7		102.8		114.5		29.3
2017	7.0		96.5		103.5		25.6
2018	6.7		96.7		103.4		25.3
2019	6.6		97.6		104.2		25.1
Thereafter	41.8		688.0		729.8		511.5
Total minimum obligation							647.3
Interest component of obligation							(475.1		)
Present value of minimum obligation							$	172.2

^(a)  Amounts do not include PPAs accounted for as executory contracts.

^(b)  PPA operating leases contractually expire through 2032.

Schedule of Asset Retirement Obligations [Table Text Block]

A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2014 and 2013 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow Revisions			Ending Balance  Dec. 31, 2014 (a)
Electric plant
Steam and other production asbestos	$	23,914	$	747	$	1,597	$	10,598		$	36,856
Steam and other production ash containment	29,234		—		1,897		30,754			61,885
Wind production	2,953		—		22		(880		)	2,095
Electric distribution	1,176		—		43		(37		)	1,182
Other	1,017		—		41		92			1,150
Natural gas plant
Gas transmission and distribution	788		18,252		50		98,384			117,474
Other	575		2,865		24		422			3,886
Common and other property
Common miscellaneous	741		—		27		—			768
Total liability	$	60,398	$	21,864	$	3,701	$	139,333		$	225,296

^(a)  There were no ARO liabilities settled during the year ended Dec. 31, 2014.

(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions			Ending Balance Dec. 31, 2013
Electric plant
Steam and other production asbestos	$	19,734	$	—	$	(941	)	$	1,247	$	3,874		$	23,914
Steam and other production ash containment	12,919		—		—			684		15,631			29,234
Wind production	2,928		—		—			25		—			2,953
Electric distribution	6,392		—		—			178		(5,394		)	1,176
Other	627		—		—			60		330			1,017
Natural gas plant
Gas transmission and distribution	842		—		—			53		(107		)	788
Other	—		575		—			—		—			575
Common and other property
Common miscellaneous	309		—		—			29		403			741
Total liability	$	43,751	$	575	$	(941	)	$	2,276	$	14,737		$	60,398

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Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) (USD $)	1 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2014		Dec. 31, 2013
Long-Term Borrowings [Line Items]
Long-term Line of Credit				$ 0
Deferred Finance Costs, Noncurrent, Net		26,500,000		37,000,000
First Mortgage Bonds | Series Due March 15, 2044
Long-Term Borrowings [Line Items]
Face amount	300,000,000
Interest rate, stated percentage (in hundredths)	4.30%	4.30%
Maturity date	Mar. 15, 2044	Mar. 15, 2044
Long-term Debt, Gross		300,000,000		0
First Mortgage Bonds | Series Due Sept. 1, 2017
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)		4.375%
Maturity date		Sep. 01, 2017
Long-term Debt, Gross		129,500,000	[1]	129,500,000	[1]
First Mortgage Bonds | Series Due Aug. 1, 2018
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)		5.80%
Maturity date		Aug. 01, 2018
Long-term Debt, Gross		300,000,000		300,000,000
First Mortgage Bonds | Series Due June 1, 2019
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)		5.125%
Maturity date		Jun. 01, 2019
Long-term Debt, Gross		400,000,000		400,000,000
First Mortgage Bonds | Series Due March 15, 2023
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)	2.50%	2.50%
Maturity date	Mar. 15, 2023	Mar. 15, 2023
Long-term Debt, Gross		250,000,000		250,000,000
First Mortgage Bonds | Series Due March 15, 2043
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)	3.95%	3.95%
Maturity date	Mar. 15, 2043	Mar. 15, 2043
Long-term Debt, Gross		$ 250,000,000		$ 250,000,000

[1] Pollution control financing.

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0		$ 0		$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0		0		0
Designated as Hedging Instrument [Member] | Cash Flow Hedges [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	(115,000)		14,000		(15,019,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(755,000)		(770,000)		(1,908,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		0
Designated as Hedging Instrument [Member] | Cash Flow Hedges [Member] | Interest Rate [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		(15,082,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(730,000)	[1]	(730,000)	[1]	(1,819,000)	[1]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		0
Designated as Hedging Instrument [Member] | Cash Flow Hedges [Member] | Vehicle Fuel And Other Commodity [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	(115,000)		14,000		63,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(25,000)	[2]	(40,000)	[2]	(89,000)	[2]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		0
Other Derivative Instruments [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	451,000		(4,001,000)		7,727,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	(4,631,000)		4,340,000		61,820,000
Pre-tax gains (losses) recognized during the period in income	(9,850,000)		5,850,000		(135,000)
Other Derivative Instruments [Member] | Commodity Trading [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss					0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities					0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss					0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)					0
Pre-tax gains (losses) recognized during the period in income					2,000	[3]
Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	451,000		(4,001,000)		7,727,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	(4,631,000)	[4]	4,340,000	[4]	61,820,000	[4]
Pre-tax gains (losses) recognized during the period in income	(9,850,000)	[4]	5,850,000	[5]	(137,000)	[5]
Other Derivative Instruments [Member] | Natural Gas Commodity for Electric Generation [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)					$ 5,000,000

[1] Amounts are recorded to interest charges.

[2] Amounts are 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 year ended Dec. 31, 2012 included $5.0 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses for the years ended Dec. 31, 2014 and 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2014, 2013 and 2012 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

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

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues
Electric	$ 3,125,937	$ 3,081,171	$ 2,969,899
Natural gas	1,215,324	1,080,703	962,435
Steam and other	41,888	40,754	36,959
Total operating revenues	4,383,149	4,202,628	3,969,293
Operating expenses
Electric fuel and purchased power	1,405,498	1,335,818	1,235,343
Cost of natural gas sold and transported	725,754	621,120	532,417
Cost of sales — steam and other	16,831	17,039	15,438
Operating and maintenance expenses	751,786	762,322	742,975
Demand side management program expenses	139,780	139,337	123,205
Depreciation and amortization	379,202	360,417	338,827
Taxes (other than income taxes)	161,928	137,816	131,869
Total operating expenses	3,580,779	3,373,869	3,120,074
Operating income	802,370	828,759	849,219
Other income, net	4,265	3,136	4,736
Allowance for funds used during construction — equity	46,784	33,173	16,354
Interest charges and financing costs
Interest charges — includes other financing costs of $6,340, $6,866, and $7,088, respectively	171,881	173,602	188,094
Allowance for funds used during construction — debt	(17,241)	(12,657)	(8,405)
Total interest charges and financing costs	154,640	160,945	179,689
Income before income taxes	698,779	704,123	690,620
Income taxes	243,591	250,740	232,544
Net income	$ 455,188	$ 453,383	$ 458,076

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2014
Operating revenues	$	1,203,543	$	993,704	$	1,049,111	$	1,136,791
Operating income	208,437		163,437		261,073		169,423
Net income	118,403		89,792		154,159		92,834

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
Operating revenues	$	1,117,457	$	966,429	$	1,044,300	$	1,074,442
Operating income	212,299		183,675		289,741		143,044
Net income	116,605		97,299		166,266		73,213

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities
Net income	$ 455,188	$ 453,383	$ 458,076
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	383,992	365,713	344,226
Demand side management program amortization	4,331	4,802	5,299
Deferred income taxes	227,823	316,253	38,092
Amortization of investment tax credits	(2,941)	(2,935)	(2,957)
Allowance for equity funds used during construction	(46,784)	(33,173)	(16,354)
Provision for bad debts	17,005	16,784	16,323
Pretax charge for project costs	0	0	10,666
Net realized and unrealized hedging and derivative transactions	(2,578)	(3,571)	(39,338)
Changes in operating assets and liabilities:
Accounts receivable	(42,921)	5,089	(58,226)
Accrued unbilled revenues	(23,132)	14,707	18,920
Inventories	(972)	(14,857)	30,203
Prepayments and other	(81,715)	(7,210)	(3,466)
Accounts payable	(22,789)	59,361	(56,176)
Net regulatory assets and liabilities	130,499	108,400	(31,776)
Other current liabilities	5,284	16,561	34,305
Pension and other employee benefit obligations	(38,905)	(48,886)	(57,974)
Change in other noncurrent assets	5,537	3,862	(10,101)
Change in other noncurrent liabilities	(19,130)	17,191	(1,267)
Net cash provided by (used in) operating activities	947,792	1,271,474	678,475
Investing activities
Utility capital/construction expenditures	(1,114,338)	(1,066,700)	(873,383)
Allowance for equity funds used during construction	46,784	33,173	16,354
Investments in utility money pool arrangement	(603,000)	(1,495,000)	(1,000,000)
Repayments from utility money pool arrangement	659,000	1,423,000	1,052,000
Net cash provided by (used in) investing activities	(1,011,554)	(1,105,527)	(805,029)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	382,000	(154,000)	154,000
Borrowings under utility money pool arrangement	333,000	14,000	36,000
Repayments under utility money pool arrangement	(333,000)	(14,000)	(36,000)
Proceeds from issuance of long-term debt	295,598	492,313	790,379
Repayments of long-term debt	(275,000)	(250,000)	(648,750)
Capital contributions from parent	81,498	25,621	99,283
Dividends paid to parent	(433,788)	(263,942)	(266,971)
Net cash provided by (used in) financing activities	50,308	(150,008)	127,941
Net change in cash and cash equivalents	(13,454)	15,939	1,387
Cash and cash equivalents at beginning of period	21,089	5,150
Cash and cash equivalents at end of period	7,635	21,089	5,150
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(150,011)	(155,457)	(179,610)
Cash received (paid) for income taxes, net	(91,810)	34,946	(179,321)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 139,616	$ 142,103	$ 94,288

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Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 3,800	$ 3,500
Net benefit cost recognized for financial reporting	600	600
Pension Plans
Pension Benefits [Abstract]
Total benefit obligation	1,277,957	1,152,836	1,194,371
Net benefit cost recognized for financial reporting	37,307	49,899	43,169
Minimum number of years historical achieved weighted average annual returns are used to determine investment return assumptions (in years)	20 years
Expected average long-term rate of return on assets (in hundredths)	6.81%	6.47%	6.65%
Expected average long-term rate of return on assets for next fiscal year (in hundredths)	6.81%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	100.00%	100.00%
Pension Plans | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	32.00%	29.00%
Pension Plans | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	35.00%	36.00%
Pension Plans | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	12.00%	14.00%
Pension Plans | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	18.00%	19.00%
Pension Plans | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	3.00%	2.00%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	46,500	36,500
Net benefit cost recognized for financial reporting	$ 4,700	$ 6,600

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	Dec. 31, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.9	$	2.5
Unrecognized tax benefit — Temporary tax positions	10.0		5.9
Total unrecognized tax benefit	$	11.9	$	8.4

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

(Millions of Dollars)	2014			2013			2012
Balance at Jan. 1	$	8.4		$	9.6		$	11.4
Additions based on tax positions related to the current year	3.7			3.9			1.9
Reductions based on tax positions related to the current year	(0.7		)	—			(1.5		)
Additions for tax positions of prior years	2.8			3.3			2.0
Reductions for tax positions of prior years	(1.2		)	(0.9		)	(4.2		)
Settlements with taxing authorities	(1.1		)	(7.5		)	—
Balance at Dec. 31	$	11.9		$	8.4		$	9.6

Tax Benefits Associated with NOL and Tax Credit Carryforwards

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

(Millions of Dollars)	Dec. 31, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(3.9	)	$	(7.0	)

NOL and Tax Credit Carryforwards

Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2014		2013
Federal NOL carryforward	$	319.5	$	315.5
Federal tax credit carryforwards	22.3		19.4
State NOL carryforwards	690.1		664.6
State tax credit carryforwards, net of federal detriment	12.2		11.2

Schedule of Effective Income Tax Rate Reconciliation

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.  The following reconciles such differences for the years ending Dec. 31:

	2014		2013		2012
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	2.8		3.0		2.3
Change in unrecognized tax benefits	(0.1	)	0.1		0.1
Regulatory differences — utility plant items	(2.1	)	(1.4	)	(0.6	)
Tax credits recognized, net of federal income tax expense	(0.8	)	(0.8	)	(0.6	)
Prescription drug tax benefit and Medicare Part D	—		—		(2.5	)
Other, net	0.1		(0.3	)	—
Effective income tax rate	34.9	%	35.6	%	33.7	%

Schedule of Components of Income Tax Expense (Benefit)

The components of income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2014			2013			2012
Current federal tax (benefit) expense	$	9,550		$	(52,408	)	$	176,354
Current state tax (benefit) expense	2,611			(7,252		)	24,502
Current change in unrecognized tax (benefit) expense	6,548			(2,918		)	(3,447		)
Deferred federal tax expense	208,781			273,916			38,309
Deferred state tax expense (benefit)	26,196			38,243			(4,424		)
Deferred change in unrecognized tax expense (benefit)	(7,154		)	4,094			4,207
Deferred investment tax credits	(2,941		)	(2,935		)	(2,957		)
Total income tax expense	$	243,591		$	250,740		$	232,544

The components of deferred income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2014			2013			2012
Deferred tax expense excluding items below	$	254,142		$	335,580		$	41,233
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(26,649		)	(19,616		)	(9,574		)
Tax benefit allocated to other comprehensive income and other	330			289			6,433
Deferred tax expense	$	227,823		$	316,253		$	38,092

Schedule of Deferred Tax Assets and Liabilities

The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:

(Thousands of Dollars)	2014		2013
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,467,260	$	2,197,685
Employee benefits	110,556		100,003
Other	140,080		132,436
Total deferred tax liabilities	$	2,717,896	$	2,430,124
Deferred tax assets:
NOL carryforward	$	143,158	$	137,043
Unbilled revenue - fuel costs	57,654		49,171
Rate refund	43,735		26,943
Tax credit carryforward	34,493		30,643
Regulatory liabilities	14,549		14,893
Deferred investment tax credits	13,781		14,905
Other	37,472		37,614
Total deferred tax assets	$	344,842	$	311,212
Net deferred tax liability	$	2,373,054	$	2,118,912

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Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 425,282,000		$ 438,193,000		$ 425,917,000
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	23,566,000		18,202,000
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	401,716,000		419,991,000
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0		36,064,000	31,602,000
Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Cash collateral restricted for use	900,000		600,000
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	23,566,000	[1]	18,202,000	[1]
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	23,566,000	[1]	18,202,000	[1]
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[1]
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[1]
Derivatives
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	166,000		(370,000)
Derivatives | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Derivatives | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	166,000		(370,000)
Derivatives | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	43,494,000		52,028,000
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	43,494,000		52,028,000
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	45,075,000		47,029,000
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	45,075,000		47,029,000
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	48,527,000		46,186,000
Corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	48,527,000		46,186,000
Corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,240,000		2,991,000		670,000
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,240,000		2,991,000
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0		670,000	6,941,000
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	10,071,000		21,593,000
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	10,071,000		21,593,000
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0		35,394,000	24,038,000
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	252,790,000		265,620,000
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	252,790,000		265,620,000
Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(1,647,000)		(15,086,000)
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0		0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(1,647,000)		(15,086,000)
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0		$ 0

[1] Includes restricted cash of $0.9 million and $0.6 million at Dec. 31, 2014 and 2013, respectively.

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Rate Matters

12 Months Ended

Dec. 31, 2014

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Pending and Recently Concluded Regulatory Proceedings — CPUC

Colorado 2014 Electric Rate Case —In 2014, PSCo filed an electric rate case with the CPUC requesting an increase in annual revenue of approximately $136.0 million, or 4.83 percent. The requested 2015 rate increase reflected approximately $100.9 million (subsequently updated to $98.7 million) for recovery of costs associated with the CACJA project. The case also requested the initiation of a CACJA rider for 2016 and 2017, which is anticipated to increase revenue recovery by approximately $34.2 million in 2016 and then decline to approximately $29.9 million in 2017. The rate filing was based on a 2015 forecast test year, a requested ROE of 10.35 percent, an electric rate base of $6.39 billion and an equity ratio of 56 percent. As part of the filing, PSCo would transfer approximately $19.9 million from the transmission rider to base rates, which would not impact customer bills. The rider would recover incremental investment and expenses associated with the CACJA project to retire certain coal plants, add pollution control equipment to other existing coal units and add natural gas generation.

In November 2014, several parties filed answer testimony, including the CPUC Staff (Staff) and the OCC. The Staff’s position was based on an ROE of 9.11 percent and a 51.24 percent equity ratio. In addition, the Staff proposed that costs associated with the CACJA project be recovered through a rider mechanism. The OCC recommended an ROE of 9.10 percent, a 52.70 percent equity ratio and that a portion of the costs associated with the CACJA project be recovered in base rates and the remainder through a rider mechanism.

In December 2014, PSCo filed rebuttal testimony, revising its requested rate increase to $107.2 million, or 3.79 percent, reflecting an ROE of 10.25 percent and updated information for both the sales and property tax forecasts. PSCo also proposed to recover all costs associated with the CACJA project through the rider beginning in 2015.

On Jan. 23, 2015, PSCo and intervenors filed a comprehensive settlement agreement, subject to CPUC approval, which would result in an overall 2015 revenue increase of approximately $53.3 million, or 1.87 percent. Key terms of the agreement include the following:

• The settlement is based on a 2013 HTY, an ROE of 9.83 percent and an equity ratio of 56 percent;

• It includes the implementation of a forward-looking CACJA rider, effective Jan. 1, 2015, a forward-looking TCA rider, effective Feb. 13, 2015 and tracking mechanisms for pension expense and property taxes; and

• The agreement also includes an earnings test for 2015 through 2017, under which PSCo and customers would share in any earnings on a 50/50 basis if the ROE recognized falls between 9.84 percent and 10.48 percent. The earnings test principles are based primarily on those established in the previous rate case.

The Staff and OCC’s recommendations, PSCo’s rebuttal testimony and the terms of the settlement agreement are summarized as follows:

2015 Rate Request (Millions of Dollars)	Staff			OCC			PSCo Rebuttal			Settlement Agreement
PSCo’s filed rate request	$	136.0		$	136.0		$	136.0		$	136.0
Transfer from TCA rider to base rates	19.9			19.9			19.9			19.9
PSCo’s filed revenue requirement deficiency	155.9			155.9			155.9			155.9
Lower ROE	(69.1		)	(66.5		)	(6.2		)	(27.9		)
Capital structure	(20.9		)	(23.7		)	—			—
Rate base adjustments (largely the removal of prepaid pension asset)	(20.8		)	2.3			—			—
Adjustment to an HTY	(82.5		)	(82.5		)	—			(23.9		)
Adjustment to use 13-month average rate base	(26.1		)	(22.0		)	—			—
Rate base adjustments for known and measurable plant through September 2014	21.9			—			—			—
O&M expense adjustments	(7.2		)	(16.6		)	—			—
Depreciation	—			(3.8		)	—			—
Property taxes	—			(12.1		)	(5.3		)	(5.3		)
Remove CACJA from base rates	(62.4		)	—			(98.7		)	(98.7		)
Updated sales forecast	—			—			(15.2		)	(15.2		)
Prepaid pension amortization	—			—			—			9.5
Non-specified settlement adjustments	—			—			—			(31.7		)
Other, net	0.1			0.1			(2.1		)	(2.1		)
Total base rate (decrease) increase	(111.1		)	(68.9		)	28.4			(39.4		)
CACJA rider mechanism	54.2			—			98.7			97.0
TCA rider mechanism — 2015 forecast test year	—			—			—			15.6
Transfer from TCA rider to base rates	(19.9		)	(19.9		)	(19.9		)	(19.9		)
Total revenue impact	$	(76.8	)	$	(88.8	)	$	107.2		$	53.3

In addition to the revenue reflected in the table above, PSCo estimates that it will defer approximately $3.1 million of additional expenses in 2015 as a result of the settlement.

In its original rate case request, PSCo proposed to shorten the depreciable lives for certain assets, which would have resulted in a material increase in depreciation expense. As a result of the settlement, PSCo will not implement the depreciation changes, but will instead file a standalone case to address depreciation, amortization and decommissioning in early 2016. The results of the depreciation case will become effective as part of the 2018 electric rate case.

Settlement rates became effective Feb. 13, 2015 on an interim basis, subject to refund, and the CPUC is expected to issue a final decision regarding the settlement in the first quarter of 2015.

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

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

Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012-2014. In April 2014, PSCo filed its 2013 earnings test with the CPUC proposing a refund obligation of $45.7 million to electric customers. This tariff was approved by the CPUC in July 2014. As of Dec. 31, 2014, PSCo has also recognized management’s best estimate of the expected customer refund obligation for the 2014 earnings test of $74.0 million. PSCo will file its 2014 earnings test with the CPUC in April 2015. The final sharing obligation will be based on the CPUC-approved tariff and could vary from the current estimate.

SmartGridCity (SGC) Cost Recovery — PSCo requested recovery of $45 million of capital costs and $4 million of annual O&M costs incurred to develop and operate SGC as part of its 2010 electric rate case.  In 2011, the CPUC allowed recovery of approximately $28 million of the capital cost and all of the O&M costs.  PSCo subsequently requested recovery of the remaining capital investment in SGC, which the CPUC denied in April 2013.  Based on the ALJ’s previous recommended decision to deny recovery, PSCo recognized a $10.7 million pre-tax charge in 2012, representing the net book value of the disallowed investment, which was included in O&M expense.

Electric, Purchased Gas and Resource Adjustment Clauses

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

The CPUC approved the 2014 PSCo electric and gas DSM budget of $87.8 million and $12.3 million, respectively. In October 2014, PSCo filed its 2015-2016 DSM plan, which proposes a 2015 DSM electric budget of $81.6 million and a gas budget of $13.1 million and a 2016 DSM electric budget of $78.7 million and gas budget of $13.6 million. A decision by the ALJ is expected in the second quarter of 2015.

REC Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent to customers for 2014. In 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. PSCo credited to the RESA regulatory asset balance approximately $0.6 million and $21.7 million in 2014 and 2013, respectively. The cumulative credit to the RESA regulatory asset balance was $105.1 million and $104.5 million at Dec. 31, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds.

In September 2014, an ALJ issued a decision approving a settlement between PSCo, the CPUC Staff, and intervenors to extend the current sharing mechanism without modification through 2017.

Recently Concluded Regulatory Proceedings — FERC

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

In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures. Several wholesale customers then filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012.

In September 2014, PSCo and its transmission customers filed a settlement to resolve the ROE issue in the transmission rate filing and complaint. The FERC approved the settlement in October 2014, providing a 9.72 percent ROE effective retroactive to July 1, 2012 for the PSCo transmission formula rate. Refunds were provided to customers in December 2014.

Production Formula Rate ROE Complaint — In August 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo production sales formula rates effective Sept. 1, 2013. In September 2014, PSCo and its wholesale customers filed a settlement to resolve the complaint along with the pending transmission formula rate ROE matters. The FERC approved the settlement in October 2014, providing a 9.72 percent ROE effective for the PSCo production formula rate. Refunds were provided to customers in December 2014.

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Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2014

Benefit Plans and Other Postretirement Benefits [Abstract]

Projected Benefit Payments for the Pension and Postretirement Benefit Plans

The following table lists PSCo’s projected benefit payments for the pension and postretirement benefit plans:

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2015	$	74,237	$	32,300	$	2,532	$	29,768
2016	77,804		32,991		2,692		30,299
2017	77,126		33,328		2,863		30,465
2018	80,003		34,146		3,033		31,113
2019	82,472		34,053		3,192		30,861
2020-2024	423,835		165,560		18,053		147,507

Pension Plans

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year:

	2014		2013
Domestic and international equity securities	32	%	29	%
Long-duration fixed income and interest rate swap securities	35		36
Short-to-intermediate term fixed income securities	12		14
Alternative investments	18		19
Cash	3		2
Total	100	%	100	%

The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	82,486	$	—		$	—	$	82,486
Derivatives	—		508			—		508
Government securities	—		180,912			—		180,912
Corporate bonds	—		115,593			—		115,593
Asset-backed securities	—		1,360			—		1,360
Mortgage-backed securities	—		3,997			—		3,997
Common stock	37,067		—			—		37,067
Private equity investments	—		—			50,210		50,210
Commingled funds	—		629,439			—		629,439
Real estate	—		—			18,410		18,410
Securities lending collateral obligation and other	—		(16,117		)	—		(16,117		)
Total	$	119,553	$	915,692		$	68,620	$	1,103,865

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	42,721	$	—	$	—	$	42,721
Derivatives	—		14,755		—		14,755
Government securities	—		125,891		—		125,891
Corporate bonds	—		183,078		—		183,078
Asset-backed securities	—		2,356		—		2,356
Mortgage-backed securities	—		5,267		—		5,267
Common stock	34,742		—		—		34,742
Private equity investments	—		—		49,022		49,022
Commingled funds	—		582,722		—		582,722
Real estate	—		—		15,556		15,556
Securities lending collateral obligation and other	—		10,947		—		10,947
Total	$	77,463	$	925,016	$	64,578	$	1,067,057

Changes in Level 3 Plan Assets

The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2014, 2013 and 2012:

(Thousands of Dollars)	Jan. 1, 2014		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2014
Private equity investments	$	49,022	$	8,495	$	(4,299	)	$	(3,008	)	$	—	$	50,210
Real estate	15,556		1,180		(302		)	1,976			—		18,410
Total	$	64,578	$	9,675	$	(4,601	)	$	(1,032	)	$	—	$	68,620

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	4,604	$	—		$	—		$	—		$	(4,604	)	$	—
Mortgage-backed securities	12,058		—			—			—			(12,058		)	—
Private equity investments	47,056		7,074			(4,027		)	(1,081		)	—			49,022
Real estate	19,273		(870		)	3,769			3,048			(9,664		)	15,556
Total	$	82,991	$	6,204		$	(258	)	$	1,967		$	(26,326	)	$	64,578

^(a)  Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2012
Asset-backed securities	$	9,824	$	1,175	$	(1,597	)	$	(4,798	)	$	—	$	4,604
Mortgage-backed securities	23,614		550		(625		)	(11,481		)	—		12,058
Private equity investments	49,489		5,206		(7,001		)	(638		)	—		47,056
Real estate	11,230		6		1,843			6,194			—		19,273
Total	$	94,157	$	6,937	$	(7,380	)	$	(10,723	)	$	—	$	82,991

Change in Projected Benefit Obligation

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for PSCo is presented in the following table:

(Thousands of Dollars)	2014			2013
Accumulated Benefit Obligation at Dec. 31	$	1,249,739		$	1,134,184
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,152,836		$	1,194,371
Service cost	23,939			25,206
Interest cost	53,277			46,160
Transfer (to) from other plan	(13,404		)	11,306
Actuarial loss (gain)	133,215			(49,384		)
Benefit payments	(71,906		)	(74,823		)
Obligation at Dec. 31	$	1,277,957		$	1,152,836

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,067,057		$	1,055,308
Actual return on plan assets	84,871			30,684
Employer contributions	35,156			44,582
Transfer (to) from other plan	(11,313		)	11,306
Benefit payments	(71,906		)	(74,823		)
Fair value of plan assets at Dec. 31	$	1,103,865		$	1,067,057

Funded Status of Plans

(Thousands of Dollars)	2014			2013
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(174,092	)	$	(85,779	)

^(a)  Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	530,674		$	450,202
Prior service credit	(18,708		)	(21,800		)
Total	$	511,966		$	428,402

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates

(Thousands of Dollars)	2014		2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	31,774	$	36,271
Noncurrent regulatory assets	480,192		392,131
Total	$	511,966	$	428,402

Schedule of Assumptions Used

	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.75	%	4.00	%	5.00	%
Expected average long-term increase in compensation level	3.75		3.75		4.00
Expected average long-term rate of return on assets	6.81		6.47		6.65

Measurement date Dec. 31, 2014 Dec. 31, 2013

	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.11	%	4.75	%
Expected average long-term increase in compensation level	3.75		3.75
Mortality table	RP 2014		RP 2000

Components of Net Periodic Benefit Costs

Benefit Costs —The components of PSCo’s net periodic pension cost were:

(Thousands of Dollars)	2014			2013			2012
Service cost	$	23,939		$	25,206		$	22,719
Interest cost	53,277			46,160			51,192
Expected return on plan assets	(70,709		)	(63,821		)	(65,302		)
Amortization of prior service (credit) cost	(3,092		)	(1,064		)	228
Amortization of net loss	33,892			43,418			34,332
Net periodic pension cost	$	37,307		$	49,899		$	43,169

Postretirement Benefit Plan

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year:

	2014		2013
Domestic and international equity securities	25	%	41	%
Short-to-intermediate fixed income securities	57		40
Alternative investments	13		13
Cash	5		6
Total	100	%	100	%

The following tables present, for each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents (a)	$	23,566	$	—		$	—	$	23,566
Derivatives	—		166			—		166
Government securities	—		43,494			—		43,494
Insurance contracts	—		45,075			—		45,075
Corporate bonds	—		48,527			—		48,527
Asset-backed securities	—		3,240			—		3,240
Mortgage-backed securities	—		10,071			—		10,071
Commingled funds	—		252,790			—		252,790
Other	—		(1,647		)	—		(1,647		)
Total	$	23,566	$	401,716		$	—	$	425,282

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents (a)	$	18,202	$	—		$	—	$	18,202
Derivatives	—		(370		)	—		(370		)
Government securities	—		52,028			—		52,028
Insurance contracts	—		47,029			—		47,029
Corporate bonds	—		46,186			—		46,186
Asset-backed securities	—		2,991			—		2,991
Mortgage-backed securities	—		21,593			—		21,593
Commingled funds	—		265,620			—		265,620
Other	—		(15,086		)	—		(15,086		)
Total	$	18,202	$	419,991		$	—	$	438,193

^(a)  Includes restricted cash of $0.9 million and $0.6 million at Dec. 31, 2014 and 2013, respectively.

Changes in Level 3 Plan Assets

For the year ended Dec. 31, 2014 there were no assets transferred in or out of Level 3. The following tables present the changes in PSCo’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013 and 2012:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)		Purchases, Issuances and Settlements, Net		Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	670	$	—	$	—	$	—	$	(670	)	$	—
Mortgage-backed securities	35,394		—		—		—		(35,394		)	—
Total	$	36,064	$	—	$	—	$	—	$	(36,064	)	$	—

^(a)  Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2012
Asset-backed securities	$	6,941	$	(293	)	$	1,669		$	(7,647	)	$	—	$	670
Mortgage-backed securities	24,038		(641		)	3,429			8,568			—		35,394
Private equity investments	479		—			(65		)	(414		)	—		—
Real estate	144		—			35			(179		)	—		—
Total	$	31,602	$	(934	)	$	5,068		$	328		$	—	$	36,064

Change in Projected Benefit Obligation

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table:

(Thousands of Dollars)	2014			2013
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	508,971		$	599,831
Service cost	1,915			2,564
Interest cost	23,704			22,210
Medicare subsidy reimbursements	1,753			923
Plan amendments	—			(14,571		)
Plan participants’ contributions	4,625			4,589
Actuarial gain	(63,130		)	(76,889		)
Benefit payments	(34,085		)	(29,686		)
Obligation at Dec. 31	$	443,753		$	508,971

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	438,193		$	425,917
Actual return on plan assets	11,060			30,390
Plan participants’ contributions	4,625			4,589
Employer contributions	5,489			6,983
Benefit payments	(34,085		)	(29,686		)
Fair value of plan assets at Dec. 31	$	425,282		$	438,193

Funded Status of Plans

(Thousands of Dollars)	2014			2013
Funded Status at Dec. 31:
Funded status (a)	$	(18,471	)	$	(70,778	)

^(a)  Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	56,823		$	107,232
Prior service credit	(40,189		)	(46,436		)
Total	$	16,634		$	60,796

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates

(Thousands of Dollars)	2014		2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	—	$	8,798
Noncurrent regulatory assets	16,634		51,998
Total	$	16,634	$	60,796

Schedule of Assumptions Used

	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.82	%	4.10	%	5.00	%
Expected average long-term rate of return on assets	7.18		7.11		6.75

Measurement date Dec. 31, 2014 Dec. 31, 2013

	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.08	%	4.82	%
Mortality table	RP 2014		RP 2000
Health care costs trend rate — initial	6.50	%	7.00	%

Effects of One-Percent Change in Assumed Health Care Cost Trend Rate

A one-percent change in the assumed health care cost trend rate would have the following effects on PSCo:

	One-Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	45,581	$	(38,371	)
Service and interest components	3,028		(2,488		)

Components of Net Periodic Benefit Costs

Benefit Costs — The components of PSCo’s net periodic postretirement benefit costs were:

(Thousands of Dollars)	2014			2013			2012
Service cost	$	1,915		$	2,564		$	2,825
Interest cost	23,704			22,210			24,527
Expected return on plan assets	(30,214		)	(29,227		)	(25,056		)
Amortization of transition obligation	—			785			11,004
Amortization of prior service credit	(6,247		)	(7,666		)	(5,150		)
Amortization of net loss	6,434			13,699			10,930
Net periodic postretirement benefit (credit) cost	(4,408		)	2,365			19,080
Additional cost recognized due to effects of regulation	—			—			3,891
Net benefit (credit) cost recognized for financial reporting	$	(4,408	)	$	2,365		$	22,971

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

PSCo’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of PSCo no longer allow for the application of regulatory accounting guidance under GAAP, PSCo would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.

The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2014 and 2013 were:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	32,195	$	500,889	$	45,504	$	447,752
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		141,214		—		116,477
Contract valuation adjustments (b)	10	Term of related contract	8,901		12,999		3,620		16,474
Depreciation differences	1	One to seventeen years	10,700		104,743		10,917		95,844
Net AROs (c)	1, 12	Plant lives	—		46,213		—		39,986
Conservation programs (d)	1, 11	One to five years	10,198		10,906		13,883		19,430
Gas pipeline inspection costs	12	One to four years	5,416		3,611		5,416		14,978
Renewable resources and environmental initiatives	12	One to two years	—		—		22,325		—
Purchased power contract costs	12	Term of related contract	858		29,596		—		30,069
Losses on reacquired debt	4	Term of related debt	1,426		8,378		1,572		9,804
Recoverable purchased natural gas and electric energy costs	1	Less than one year	18,410		—		18,022		—
Property tax		One to three years	28,024		31,429		18,427		30,626
Other		Various	3,992		13,995		10,477		4,597
Total regulatory assets			$	120,120	$	903,973	$	150,163	$	826,037

^(a)  Includes $4.5 million and $4.1 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2014 and 2013, respectively.

^(b)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(c)  Includes amounts recorded for future recovery of AROs.

^(d)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2014 and 2013 were:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	366,359	$	—	$	359,387
Deferred electric, gas and steam production costs	1	Less than one year	24,035		—		33,247		—
Investment tax credit deferrals	1, 7	Various	—		22,225		—		24,038
Deferred income tax adjustment	1	Various	—		18,672		—		18,770
Conservation programs (a)	1, 11	Less than one year	32,226		—		12,188		—
Renewable resources and environmental initiatives	11, 12	Various	3,308		10,376		—		1,412
Low income discount program		Less than one year	1,680		—		4,084		—
Gain from asset sales		One to three years	316		4		1,687		368
PSCo earnings test	11	One to two years	57,127		42,819		22,892		19,203
Gas pipeline inspection costs	12	One to four years	13,970		642		—		—
Other		Various	1,797		3,324		5,401		1,512
Total regulatory liabilities			$	134,459	$	464,421	$	79,499	$	424,690

^(a)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

At Dec. 31, 2014 and 2013, approximately $104 million and $136 million of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with renewable resources and environmental initiatives.

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Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Pension Plans
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2015	$ 74,237
2016	77,804
2017	77,126
2018	80,003
2019	82,472
2020-2024	423,835
Postretirement Benefit Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2015	32,300
2016	32,991
2017	33,328
2018	34,146
2019	34,053
2020-2024	165,560
Expected Medicare Part D Subsidies [Abstract]
2015	2,532
2016	2,692
2017	2,863
2018	3,033
2019	3,192
2020-2024	18,053
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2015	29,768
2016	30,299
2017	30,465
2018	31,113
2019	30,861
2020-2024	$ 147,507

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 7,635	$ 21,089
Accounts receivable, net	322,885	328,675
Accounts receivable from affiliates	50,842	19,136
Investments in utility money pool arrangement	16,000	72,000
Accrued unbilled revenues	294,049	270,917
Inventories	238,979	238,007
Regulatory assets	120,120	150,163
Deferred income taxes	64,587	87,267
Derivative instruments	1,731	6,576
Prepaid Taxes	90,365	9,439
Prepayments and other	23,979	23,190
Total current assets	1,231,172	1,226,459
Property, plant and equipment, net	11,626,956	10,742,397
Other assets
Regulatory assets	903,973	826,037
Derivative instruments	5,176	6,905
Other	48,506	52,520
Total other assets	957,655	885,462
Total assets	13,815,783	12,854,318
Current liabilities
Current portion of long-term debt	8,178	282,143
Short-term debt	382,000	0
Accounts payable	425,133	451,243
Accounts payable to affiliates	46,736	45,902
Regulatory liabilities	134,459	79,499
Taxes accrued	159,470	154,194
Accrued interest	48,409	48,492
Dividends payable to parent	83,652	65,134
Derivative instruments	5,774	6,734
Other	72,002	89,571
Total current liabilities	1,365,813	1,222,912
Deferred credits and other liabilities
Deferred income taxes	2,437,641	2,206,179
Deferred investment tax credits	36,273	39,230
Regulatory liabilities	464,421	424,690
Asset retirement obligations	225,296	60,398
Derivative instruments	18,257	23,366
Customer advances	229,990	251,062
Pension and employee benefit obligations	202,031	167,127
Other	68,171	66,855
Total deferred credits and other liabilities	3,682,080	3,238,907
Commitments and contingencies
Capitalization
Long-term debt	3,882,051	3,590,500
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2014 and 2013, respectively	0	0
Additional paid in capital	3,522,788	3,441,290
Retained earnings	1,386,929	1,384,047
Accumulated other comprehensive loss	(23,878)	(23,338)
Total common stockholder’s equity	4,885,839	4,801,999
Total liabilities and equity	$ 13,815,783	$ 12,854,318

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Interest charges and financing costs
Other financing costs	$ 6,340	$ 6,866	$ 7,088

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Joint Ownership of Generation, Transmission and Gas Facilities Joint Ownership of Generation, Transmission and Gas Facilities

12 Months Ended

Dec. 31, 2014

Joint Ownership of Generation, Transmission and Gas Facilities [Abstract]

Joint Ownership of Generation, Transmission and Gas Facilities

Joint Ownership of Generation, Transmission and Gas Facilities

Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2014:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	98,145	$	66,333	$	1,405	75.5	%
Hayden Unit 2	121,571		59,999		8,867		37.4
Hayden Common Facilities	37,049		16,928		135		53.1
Craig Units 1 and 2	59,860		35,573		3,013		9.7
Craig Common Facilities 1, 2 and 3	36,890		17,735		527		6.5
Comanche Unit 3	883,971		81,748		64		66.7
Comanche Common Facilities	23,624		1,051		308		82.0
Electric Transmission:
Transmission and other facilities, including substations	151,301		60,847		1,730		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	16,278		5,594		—		60.0
Total	$	1,428,689	$	345,808	$	16,049

PSCo has approximately 820 MW of jointly owned generating capacity.  PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts.  Each of the respective owners is responsible for providing its own financing.

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Summarized Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 1,136,791	$ 1,049,111	$ 993,704	$ 1,203,543	$ 1,074,442	$ 1,044,300	$ 966,429	$ 1,117,457	$ 4,383,149	$ 4,202,628	$ 3,969,293
Operating income	169,423	261,073	163,437	208,437	143,044	289,741	183,675	212,299	802,370	828,759	849,219
Net income	$ 92,834	$ 154,159	$ 89,792	$ 118,403	$ 73,213	$ 166,266	$ 97,299	$ 116,605	$ 455,188	$ 453,383	$ 458,076

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 20, 2015	Jun. 30, 2014
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
Entity Public Float			$ 0
Document Type	10-K
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Entity Common Stock, Shares Outstanding		100

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Income Taxes Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Tax Increase Prevention Act of 2014— In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following:

• The R&E credit was extended for 2014;

• PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and

• 50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.

The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment.

American Taxpayer Relief Act of 2012— In 2013, the American Taxpayer Relief Act (ATRA) was signed into law. The ATRA provided for the following:

• The top tax rate for dividends increased from 15 percent to 20 percent. The 20 percent dividend rate is now consistent with the tax rates for capital gains;

• The R&E credit was extended for 2012 and 2013;

• PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; and

• 50 percent bonus depreciation was extended one year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation.

The accounting related to the ATRA, including the provisions related to 2012, was recorded beginning in the first quarter of 2013 because a change in tax law is accounted for in the period of enactment.

Prescription drug tax benefit— In the third quarter of 2012, PSCo implemented a tax strategy related to the allocation of funding of PSCo’s retiree prescription drug plan.  This strategy restored a portion of the tax benefit associated with federal subsidies for prescription drug plans that had been accrued since 2004 and was expensed in 2010.  As a result, PSCo recognized approximately $17 million of income tax benefit.

Medicare Part D— In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. PSCo is not expected to accrue any income tax expense related to this adjustment. At Dec. 31, 2014, the IRS has begun the Appeals process; however, the outcome and timing of a resolution is uncertain.

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

Unrecognized Tax Benefits— The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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)	Dec. 31, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.9	$	2.5
Unrecognized tax benefit — Temporary tax positions	10.0		5.9
Total unrecognized tax benefit	$	11.9	$	8.4

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

(Millions of Dollars)	2014			2013			2012
Balance at Jan. 1	$	8.4		$	9.6		$	11.4
Additions based on tax positions related to the current year	3.7			3.9			1.9
Reductions based on tax positions related to the current year	(0.7		)	—			(1.5		)
Additions for tax positions of prior years	2.8			3.3			2.0
Reductions for tax positions of prior years	(1.2		)	(0.9		)	(4.2		)
Settlements with taxing authorities	(1.1		)	(7.5		)	—
Balance at Dec. 31	$	11.9		$	8.4		$	9.6

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

(Millions of Dollars)	Dec. 31, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(3.9	)	$	(7.0	)

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

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2014, 2013 and 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2014, 2013 or 2012.

Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2014		2013
Federal NOL carryforward	$	319.5	$	315.5
Federal tax credit carryforwards	22.3		19.4
State NOL carryforwards	690.1		664.6
State tax credit carryforwards, net of federal detriment	12.2		11.2

The federal carryforward periods expire between 2021 and 2034.  The state carryforward periods expire between 2017 and 2033.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.  The following reconciles such differences for the years ending Dec. 31:

	2014		2013		2012
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	2.8		3.0		2.3
Change in unrecognized tax benefits	(0.1	)	0.1		0.1
Regulatory differences — utility plant items	(2.1	)	(1.4	)	(0.6	)
Tax credits recognized, net of federal income tax expense	(0.8	)	(0.8	)	(0.6	)
Prescription drug tax benefit and Medicare Part D	—		—		(2.5	)
Other, net	0.1		(0.3	)	—
Effective income tax rate	34.9	%	35.6	%	33.7	%

The components of income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2014			2013			2012
Current federal tax (benefit) expense	$	9,550		$	(52,408	)	$	176,354
Current state tax (benefit) expense	2,611			(7,252		)	24,502
Current change in unrecognized tax (benefit) expense	6,548			(2,918		)	(3,447		)
Deferred federal tax expense	208,781			273,916			38,309
Deferred state tax expense (benefit)	26,196			38,243			(4,424		)
Deferred change in unrecognized tax expense (benefit)	(7,154		)	4,094			4,207
Deferred investment tax credits	(2,941		)	(2,935		)	(2,957		)
Total income tax expense	$	243,591		$	250,740		$	232,544

The components of deferred income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2014			2013			2012
Deferred tax expense excluding items below	$	254,142		$	335,580		$	41,233
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(26,649		)	(19,616		)	(9,574		)
Tax benefit allocated to other comprehensive income and other	330			289			6,433
Deferred tax expense	$	227,823		$	316,253		$	38,092

The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:

(Thousands of Dollars)	2014		2013
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,467,260	$	2,197,685
Employee benefits	110,556		100,003
Other	140,080		132,436
Total deferred tax liabilities	$	2,717,896	$	2,430,124
Deferred tax assets:
NOL carryforward	$	143,158	$	137,043
Unbilled revenue - fuel costs	57,654		49,171
Rate refund	43,735		26,943
Tax credit carryforward	34,493		30,643
Regulatory liabilities	14,549		14,893
Deferred investment tax credits	13,781		14,905
Other	37,472		37,614
Total deferred tax assets	$	344,842	$	311,212
Net deferred tax liability	$	2,373,054	$	2,118,912

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Commitments and Contingencies, Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 Lease		Dec. 31, 2013	Dec. 31, 2012
Capital Leases [Abstract]
Number of leases qualifying as capital leases	3
Amortization expense under capital lease assets	$ 7,200,000		$ 6,300,000	$ 5,700,000
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease	221,200,000		221,200,000
Accumulated depreciation	(49,000,000)		(41,800,000)
Total property held under capital leases, net	172,200,000		179,400,000
Operating Leases, Future Minimum Payments Due [Abstract]
2015	128,300,000
2016	114,500,000
2017	103,500,000
2018	103,400,000
2019	104,200,000
Thereafter	729,800,000
Capital Leases, Future Minimum Payments Due [Abstract]
2015	30,500,000
2016	29,300,000
2017	25,600,000
2018	25,300,000
2019	25,100,000
Thereafter	511,500,000
Total minimum obligation	647,300,000
Interest component of obligation	(475,100,000)
Present value of minimum obligation	172,200,000
Maximum [Member]
Operating Leased Assets [Line Items]
Purchase Power Agreement Duration, Maximum	2032
Purchased Power Agreements [Member]
Operating Leases [Abstract]
Payments for capacity for PPAs under operating lease obligations	110,100,000		79,600,000	59,400,000
Operating Leases, Future Minimum Payments Due [Abstract]
2015	113,800,000	[1],[2]
2016	102,800,000	[1],[2]
2017	96,500,000	[1],[2]
2018	96,700,000	[1],[2]
2019	97,600,000	[1],[2]
Thereafter	688,000,000	[1],[2]
WYCO Totem Gas Storage Facilities [Member]
Capital Leases [Abstract]
Ownership interest in joint venture (in hundredths)	50.00%
Capital lease obligations	138,900,000		144,200,000
Storage, Leaseholds and Rights [Member]
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease	200,500,000		200,500,000
Gas Pipeline [Member]
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease	20,700,000		20,700,000
Other [Member]
Operating Leases [Abstract]
Total expenses under operating lease obligations	126,200,000		96,600,000	77,900,000
Operating Leases, Future Minimum Payments Due [Abstract]
2015	14,500,000
2016	11,700,000
2017	7,000,000
2018	6,700,000
2019	6,600,000
Thereafter	$ 41,800,000

[1] PPA operating leases contractually expire through 2032.

[2] Amounts do not include PPAs accounted for as executory contracts.

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues
Electric	$ 9,614	$ 8,136	$ 9,271
Other	4,441	4,441	4,441
Operating expenses
Purchased power	23	1,331	6,539
Other operating expenses - paid to Xcel Energy Services Inc.	454,250	375,766	316,548
Interest expense	158	132	114
Interest income	61	273	122
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	50,842	19,136
Accounts payable	46,736	45,902
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	18,065
Accounts payable	6,706	0
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	22	8
Accounts payable	0	0
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	5,803	1,056
Accounts payable	0	0
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	45,017	7
Accounts payable	$ 40,030	$ 45,902

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Comprehensive income:
Net income	$ 455,188	$ 453,383	$ 458,076
Derivative instruments:
Net fair value (decrease) increase, net of tax of $(43), $5 and $(5,708), respectively	(72)	9	(9,311)
Reclassification of gains to net income, net of tax of $(287), $(294) and $(725), respectively	(468)	(476)	(1,183)
Other comprehensive loss	(540)	(467)	(10,494)
Comprehensive income	$ 454,648	$ 452,916	$ 447,582

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Business and System of Accounts— PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  PSCo’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation— PSCo’s consolidated financial statements include its wholly-owned subsidiaries.  In the consolidation process, all intercompany transactions and balances are eliminated.  PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities.  PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.  See Note 6 for further discussion of jointly owned generation, transmission, and gas facilities and related ownership percentages.

PSCo evaluates its arrangements and contracts with other entities, including but not limited to, investments, PPAs and fuel contracts to determine if the other party is a variable interest entity, if PSCo has a variable interest and if PSCo is the primary beneficiary.  PSCo follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether PSCo is a variable interest entity’s primary beneficiary.  See Note 12 for further discussion of variable interest entities.

Use of Estimates— In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available.  Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs.  The recorded estimates are revised when better information becomes available or when actual amounts can be determined.  Those revisions can affect operating results.

Regulatory Accounting— PSCo accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

• Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on PSCo’s financial condition, results of operations and cash flows.  See Note 13 for further discussion of regulatory assets and liabilities.

Revenue Recognition— Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.  PSCo presents its revenue net of any excise or other fiduciary-type taxes or fees.

PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems.  These programs include approximately sixteen unique DSM products for commercial and industrial customers, as well as approximately one dozen DSM products for residential customers. Each DSM product may include one or up to several hundred measures that qualify for rebates and/or incentives.

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms.  The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals.  PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Property, Plant and Equipment and Depreciation— Property, plant and equipment is stated at original cost.  The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC.  The cost of plant retired is charged to accumulated depreciation and amortization.  Amounts recovered in rates for future removal costs are recorded as regulatory liabilities.  Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

PSCo records depreciation expense related to its plant using the straight-line method over the plant’s useful life.  Actuarial life studies are performed and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.7, 2.8 and 2.6 percent for the years ended Dec. 31, 2014, 2013 and 2012, respectively.

Leases — PSCo evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 12 for further discussion of leases.

AFUDC— AFUDC represents the cost of capital used to finance utility construction activity.  AFUDC is computed by applying a composite financing rate to qualified CWIP.  The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital).  AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates.

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases, including certain generation and transmission projects, the CPUC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.  In other cases, the CPUC has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.

AROs— PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. PSCo also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 12 for further discussion of AROs.

Income Taxes— PSCo accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements.  PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.  In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property.  Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.

PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  PSCo recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.  Recognition of changes in uncertain tax positions are reflected as a component of income tax.

PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as combined or separate state income tax returns.  Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings.  Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 7 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments— PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, and commodity trading activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.  PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customer, see Note 10.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge).  Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

PSCo evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

See Note 10 for further discussion of PSCo’s risk management and derivative activities.

Commodity Trading Operations— All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.  See Note 10 for further discussion.

Fair Value Measurements— PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value.  See Note 10 for further discussion.

Cash and Cash Equivalents— PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts— Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

Inventory— All inventory is recorded at average cost.

RECs — RECs aremarketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources.  RECs are awarded upon delivery of the associated energy and can be bought and sold.  RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced.  PSCo acquires RECs from the generation or purchase of renewable power.

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost.  The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.  As a result of state regulatory orders, PSCo records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.  The sales of RECs for trading purposes are recorded in electric utility operating revenues, net of the cost of the RECs, transaction costs, and amounts credited to customers under margin-sharing mechanisms.

Emission Allowances — Emission allowances, including the annual SO₂ and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees.  PSCo follows the inventory accounting model for all emission allowances.  Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

Environmental Costs— Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the liability can be reasonably estimated.  Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed.  If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 12 for further discussion of environmental costs.

Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 8 for further discussion of benefit plans and other postretirement benefits.

Guarantees — PSCo recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2014 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2014
Common Stockholder's Equity
Common stock, shares authorized (in shares)	100
Common stock, par value (in dollars per share)	0.01
Common stock, shares outstanding (in shares)	100
First Mortgage Bonds | Series Due April 1, 2014
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	5.50%
Debt instrument, maturity date	Apr. 01, 2014
First Mortgage Bonds | Series Due Sept. 1, 2017
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	4.375%
Debt instrument, maturity date	Sep. 01, 2017
First Mortgage Bonds | Series Due Aug. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	5.80%
Debt instrument, maturity date	Aug. 01, 2018
First Mortgage Bonds | Series Due June 1, 2019
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	5.125%
Debt instrument, maturity date	Jun. 01, 2019
First Mortgage Bonds | Series Due Nov. 15, 2020
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	3.20%
Debt instrument, maturity date	Nov. 15, 2020
First Mortgage Bonds | Series Due Sept. 15, 2022
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	2.25%
Debt instrument, maturity date	Sep. 15, 2022
First Mortgage Bonds | Series Due March 15, 2023
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	2.50%
Debt instrument, maturity date	Mar. 15, 2023
First Mortgage Bonds | Series Due Sept. 1, 2037
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	6.25%
Debt instrument, maturity date	Sep. 01, 2037
First Mortgage Bonds | Series Due Aug. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	6.50%
Debt instrument, maturity date	Aug. 01, 2038
First Mortgage Bonds | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	4.75%
Debt instrument, maturity date	Aug. 15, 2041
First Mortgage Bonds | Series Due Sept. 15, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	3.60%
Debt instrument, maturity date	Sep. 15, 2042
First Mortgage Bonds | Series Due March 15, 2043
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	3.95%
Debt instrument, maturity date	Mar. 15, 2043
First Mortgage Bonds | Series Due March 15, 2044
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	4.30%
Debt instrument, maturity date	Mar. 15, 2044
Capital Lease Obligations
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage rate range, minimum (in hundredths)	11.20%
Debt instrument, interest rate, stated percentage rate range, maximum (in hundredths)	14.30%
Debt instrument, maturity date range, end	Dec. 31, 2060

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Commitments

Capital Commitments — PSCo has made commitments in connection with a portion of its projected capital expenditures. PSCo’s capital commitments primarily relate to the following major project.

Gas Transmission Integrity Management Programs – PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include primarily system renewal projects.

Fuel Contracts— PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2015 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.

The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2014, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2015	$	321.0	$	298.3	$	136.3
2016	261.3		153.0		79.6
2017	193.6		158.8		54.8
2018	42.4		212.3		53.9
2019	43.2		221.7		51.8
Thereafter	384.0		732.7		831.1
Total	$	1,245.5	$	1,776.8	$	1,207.5

Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. PSCo’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

PPAs— PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2032 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $69.5 million, $72.7 million and $119.5 million in 2014, 2013 and 2012, respectively. At Dec. 31, 2014, the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:

(Millions of Dollars)	Capacity		Energy (a)
2015	$	82.9	$	49.5
2016	58.4		22.5
2017	35.0		4.0
2018	27.8		—
2019	19.0		—
Thereafter	47.6		—
Total	$	270.7	$	76.0

^(a)  Excludes contingent energy payments for renewable energy PPAs.

Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.

Leases— PSCo leases a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair-market value or the present value of future lease payments and are amortized over the term of the contract.

WYCO was formed as a joint venture between Xcel Energy Inc. and Colorado Interstate Gas Company, LLC (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO, and PSCo has no direct ownership interest. WYCO generally leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $138.9 million and $144.2 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2014 and 2013, respectively.

PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $7.2 million, $6.3 million, and $5.7 million for 2014, 2013 and 2012, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(49.0		)	(41.8		)
Total property held under capital leases, net	$	172.2		$	179.4

The remainder of the leases, primarily for certain PPAs, office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment are accounted for as operating leases. Total expenses under operating lease obligations were approximately $126.2 million, $96.6 million and $77.9 million for 2014, 2013 and 2012, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $110.1 million, $79.6 million and $59.4 million in 2014, 2013 and 2012, respectively, recorded to electric fuel and purchased power expenses.

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are:

(Millions of Dollars)	Operating Leases		PPA (a) (b) Operating Leases		Total Operating Leases		Capital Leases
2015	$	14.5	$	113.8	$	128.3	$	30.5
2016	11.7		102.8		114.5		29.3
2017	7.0		96.5		103.5		25.6
2018	6.7		96.7		103.4		25.3
2019	6.6		97.6		104.2		25.1
Thereafter	41.8		688.0		729.8		511.5
Total minimum obligation							647.3
Interest component of obligation							(475.1		)
Present value of minimum obligation							$	172.2

^(a)  Amounts do not include PPAs accounted for as executory contracts.

^(b)  PPA operating leases contractually expire through 2032.

Variable Interest Entities— The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

PPAs — Under certain PPAs, PSCo purchases power from independent power producing entities 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 has determined that certain independent power producing entities are variable interest entities. PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future, required to be provided other than contractual payments for energy and capacity set forth in the PPAs.

PSCo has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. 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. PSCo had approximately 1,802 MW and 1,441 MW of capacity under long-term PPAs as of Dec. 31, 2014, and 2013, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032.

Environmental Contingencies

PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense.

Site Remediation— Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent hazardous materials and wastes to that site.

MGP Sites— PSCo is currently involved in investigating and/or remediating several MGP sites where hazardous or other regulated materials may have been deposited. PSCo has identified two sites where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. PSCo anticipates that the majority of the remediation at these sites will continue through at least 2015. PSCo had accrued $1.8 million and $1.2 million for both of these sites at Dec. 31, 2014 and 2013, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and Waste

Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. PSCo has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017, but no later than July 2022. The impact of this rule on PSCo is uncertain at this time.

Federal CWA Section 316(b) — Section 316(b) of the federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. At Dec. 31, 2014, the estimated cost of compliance for PSCo did not have a material impact on the results of operations, financial position or cash flows.

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

Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2010, the EPA published a proposed rule on the regulation of coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. The EPA issued a pre-publication version of the final rule in December 2014, which once promulgated will impose new rules to regulate coal ash as a nonhazardous solid waste. PSCo’s costs for the management and disposal of coal ash will not significantly increase under the new rule.

Air

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

GHG NSPS Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. A final rule is anticipated in mid-summer 2015. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

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

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. PSCo expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. It is not yet known what impact the Supreme Court’s decision may have on the MATS standard or its implementation schedule. PSCo believes EGU MATS costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. In 2005, the EPA amended the 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 SIP, Colorado identified the PSCo facilities that will have to reduce SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a SIP that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Installation of emission controls at Pawnee was completed in 2014 at a cost of $272.6 million. Installation of the emission controls at Hayden Unit 1 is scheduled for 2015 and Hayden Unit 2 is scheduled for 2016 at an estimated combined cost of $84.6 million. PSCo anticipates these costs will be fully recoverable in rates.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10^th Circuit to review the EPA’s decision approving the SIP. WildEarth Guardians has stated it will challenge the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that SCR be added to the units. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October 2014, the Court granted the EPA’s request and vacated the current briefing schedule. The EPA has provided required status reports.

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

Revisions to the National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where PSCo operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In December 2014, the EPA issued its final designations, which did not include areas in Colorado.

Revisions to the NAAQS for Ozone— In December 2014, the EPA proposed to revise the NAAQS for ozone by lowering the eight-hour standard from 0.075 parts per million (ppm) to a level within the range of 0.065-0.070 ppm. The EPA is also taking comment on a level for the standard as low as 0.060 ppm. In Colorado, current monitored air quality concentrations are above the proposed level of 0.070 ppm in the Denver Metropolitan Area. The EPA is expected to adopt a new ozone standard in a final rule to be issued in October 2015. Depending on the level of the standard, impacted states would study the sources of the nonattainment and make emission reduction plans to attain the standards. These plans would be due to the EPA in 2020 or 2021. Such plans could include installation of further NOx controls on power plants. It is not possible to evaluate the impact of this proposal until the final standard is adopted, the designation of nonattainment areas is made in late 2017 based on air quality data years 2014-2016, and any required state plans are developed.

NOV — In 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Generating Station in Colorado. The NOV alleges that various maintenance, repair and replacement projects at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this NOV.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, wind, other and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, natural gas storage and common general property. The electric production obligations include asbestos, ash-containment facilities, radiation sources, storage tanks, control panels. The asbestos recognition associated with the electric production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. The AROs recorded for PSCo steam and other production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination dates on the ARO recognition for ash-containment facilities at steam plants were the in-service dates of the various facilities. PSCo has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract, with the origination dates being the in-service date of the various facilities.

PSCo recognized an ARO for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering, extraction and wells related to gas storage facilities. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks, radiation sources and office buildings. These assets have numerous in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

In December 2014, the EPA issued a pre-publication version of a final rule imposing requirements for activities involving coal ash waste. The ruling, once effective, will not result in the creation of a new legal obligation and PSCo’s estimated cash flows for the closure of coal ash landfills and impoundments are not expected to significantly increase as a result of the ruling.

A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2014 and 2013 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow Revisions			Ending Balance  Dec. 31, 2014 (a)
Electric plant
Steam and other production asbestos	$	23,914	$	747	$	1,597	$	10,598		$	36,856
Steam and other production ash containment	29,234		—		1,897		30,754			61,885
Wind production	2,953		—		22		(880		)	2,095
Electric distribution	1,176		—		43		(37		)	1,182
Other	1,017		—		41		92			1,150
Natural gas plant
Gas transmission and distribution	788		18,252		50		98,384			117,474
Other	575		2,865		24		422			3,886
Common and other property
Common miscellaneous	741		—		27		—			768
Total liability	$	60,398	$	21,864	$	3,701	$	139,333		$	225,296

^(a)  There were no ARO liabilities settled during the year ended Dec. 31, 2014.

(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions			Ending Balance Dec. 31, 2013
Electric plant
Steam and other production asbestos	$	19,734	$	—	$	(941	)	$	1,247	$	3,874		$	23,914
Steam and other production ash containment	12,919		—		—			684		15,631			29,234
Wind production	2,928		—		—			25		—			2,953
Electric distribution	6,392		—		—			178		(5,394		)	1,176
Other	627		—		—			60		330			1,017
Natural gas plant
Gas transmission and distribution	842		—		—			53		(107		)	788
Other	—		575		—			—		—			575
Common and other property
Common miscellaneous	309		—		—			29		403			741
Total liability	$	43,751	$	575	$	(941	)	$	2,276	$	14,737		$	60,398

Indeterminate AROs—PSCo has certain underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined; therefore, an ARO has not been recorded for these facilities.

Removal Costs — PSCo records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2014 and 2013 were $366 million and $359 million, respectively.

Legal Contingencies

PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

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

In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC issued an order on remand establishing principles for the review proceeding in October 2011. In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012.

In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive.

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

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, notwithstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter.

Other Contingencies

See Note 11 for further discussion.

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Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, PSCo accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. PSCo is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, PSCo accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for PSCo employees.

Xcel Energy, which includes PSCo, offers various benefit plans to its employees. Approximately 77 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2014, PSCo had 2,063 bargaining employees covered under a collective-bargaining agreement, which expired in May 2014. While collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended until the parties reach an agreement or a decision is rendered by an arbitrator.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets 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 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 included in Level 3 are those with inputs requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents —The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Derivative Instruments —Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Pension Benefits

Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2014 and 2013 were $46.5 million and $36.5 million, respectively, of which $3.8 million and $3.5 million were attributable to PSCo. In 2014 and 2013, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4.7 million and $6.6 million, respectively, of which $0.6 million in each year was attributable to PSCo. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

• Investment returns in 2014 were above the assumed levels of 6.81 percent;

• Investment returns in 2013 were below the assumed level of 6.47 percent;

• Investment returns in 2012 were above the assumed level of 6.65 percent; and

• In 2015, PSCo’s expected investment-return assumption is 6.81 percent.

The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year:

	2014		2013
Domestic and international equity securities	32	%	29	%
Long-duration fixed income and interest rate swap securities	35		36
Short-to-intermediate term fixed income securities	12		14
Alternative investments	18		19
Cash	3		2
Total	100	%	100	%

The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	82,486	$	—		$	—	$	82,486
Derivatives	—		508			—		508
Government securities	—		180,912			—		180,912
Corporate bonds	—		115,593			—		115,593
Asset-backed securities	—		1,360			—		1,360
Mortgage-backed securities	—		3,997			—		3,997
Common stock	37,067		—			—		37,067
Private equity investments	—		—			50,210		50,210
Commingled funds	—		629,439			—		629,439
Real estate	—		—			18,410		18,410
Securities lending collateral obligation and other	—		(16,117		)	—		(16,117		)
Total	$	119,553	$	915,692		$	68,620	$	1,103,865

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	42,721	$	—	$	—	$	42,721
Derivatives	—		14,755		—		14,755
Government securities	—		125,891		—		125,891
Corporate bonds	—		183,078		—		183,078
Asset-backed securities	—		2,356		—		2,356
Mortgage-backed securities	—		5,267		—		5,267
Common stock	34,742		—		—		34,742
Private equity investments	—		—		49,022		49,022
Commingled funds	—		582,722		—		582,722
Real estate	—		—		15,556		15,556
Securities lending collateral obligation and other	—		10,947		—		10,947
Total	$	77,463	$	925,016	$	64,578	$	1,067,057

The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2014, 2013 and 2012:

(Thousands of Dollars)	Jan. 1, 2014		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2014
Private equity investments	$	49,022	$	8,495	$	(4,299	)	$	(3,008	)	$	—	$	50,210
Real estate	15,556		1,180		(302		)	1,976			—		18,410
Total	$	64,578	$	9,675	$	(4,601	)	$	(1,032	)	$	—	$	68,620

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	4,604	$	—		$	—		$	—		$	(4,604	)	$	—
Mortgage-backed securities	12,058		—			—			—			(12,058		)	—
Private equity investments	47,056		7,074			(4,027		)	(1,081		)	—			49,022
Real estate	19,273		(870		)	3,769			3,048			(9,664		)	15,556
Total	$	82,991	$	6,204		$	(258	)	$	1,967		$	(26,326	)	$	64,578

^(a)  Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2012
Asset-backed securities	$	9,824	$	1,175	$	(1,597	)	$	(4,798	)	$	—	$	4,604
Mortgage-backed securities	23,614		550		(625		)	(11,481		)	—		12,058
Private equity investments	49,489		5,206		(7,001		)	(638		)	—		47,056
Real estate	11,230		6		1,843			6,194			—		19,273
Total	$	94,157	$	6,937	$	(7,380	)	$	(10,723	)	$	—	$	82,991

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for PSCo is presented in the following table:

(Thousands of Dollars)	2014			2013
Accumulated Benefit Obligation at Dec. 31	$	1,249,739		$	1,134,184
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,152,836		$	1,194,371
Service cost	23,939			25,206
Interest cost	53,277			46,160
Transfer (to) from other plan	(13,404		)	11,306
Actuarial loss (gain)	133,215			(49,384		)
Benefit payments	(71,906		)	(74,823		)
Obligation at Dec. 31	$	1,277,957		$	1,152,836

(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,067,057		$	1,055,308
Actual return on plan assets	84,871			30,684
Employer contributions	35,156			44,582
Transfer (to) from other plan	(11,313		)	11,306
Benefit payments	(71,906		)	(74,823		)
Fair value of plan assets at Dec. 31	$	1,103,865		$	1,067,057

(Thousands of Dollars)	2014			2013
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(174,092	)	$	(85,779	)

^(a)  Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.

(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	530,674		$	450,202
Prior service credit	(18,708		)	(21,800		)
Total	$	511,966		$	428,402

(Thousands of Dollars)	2014		2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	31,774	$	36,271
Noncurrent regulatory assets	480,192		392,131
Total	$	511,966	$	428,402

Measurement date Dec. 31, 2014 Dec. 31, 2013

	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.11	%	4.75	%
Expected average long-term increase in compensation level	3.75		3.75
Mortality table	RP 2014		RP 2000

Mortality — In 2014, the Society of Actuaries published a new mortality table and projection scale that increased the overall life expectancy of males and females. PSCo has reviewed its own population through a credibility analysis and adopted the RP 2014 table with modifications based on its population and specific experience.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2012 through 2015 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

• $90.0 million in January 2015, of which $20.0 million was attributable to PSCo;

• $130.6 million in 2014, of which $35.2 million was attributable to PSCo;

• $192.4 million in 2013, of which $44.6 million was attributable to PSCo; and

• $198.1 million in 2012, of which $41.8 million was attributable to PSCo.

For future years, Xcel Energy and PSCo anticipate contributions will be made as necessary.

Plan Amendments — In 2014 and 2013, there were no plan amendments made which affected the benefit obligation.

Benefit Costs —The components of PSCo’s net periodic pension cost were:

(Thousands of Dollars)	2014			2013			2012
Service cost	$	23,939		$	25,206		$	22,719
Interest cost	53,277			46,160			51,192
Expected return on plan assets	(70,709		)	(63,821		)	(65,302		)
Amortization of prior service (credit) cost	(3,092		)	(1,064		)	228
Amortization of net loss	33,892			43,418			34,332
Net periodic pension cost	$	37,307		$	49,899		$	43,169

	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.75	%	4.00	%	5.00	%
Expected average long-term increase in compensation level	3.75		3.75		4.00
Expected average long-term rate of return on assets	6.81		6.47		6.65

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to PSCo were $9.4 million, $11.6 million and $9.6 million in 2014, 2013 and 2012, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2015 pension cost calculations is 6.81 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for PSCo was approximately $9.1 million in 2014, $8.7 million in 2013 and $8.6 million in 2012.

Postretirement Health Care Benefits

Xcel Energy, which includes PSCo, has a contributory health and welfare benefit plan that provides health care and death benefits to certain retirees. Xcel Energy discontinued contributing toward health care benefits for former NCE, which includes PSCo, nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

In 1993, Xcel Energy Inc. and PSCo adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years.

Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year:

	2014		2013
Domestic and international equity securities	25	%	41	%
Short-to-intermediate fixed income securities	57		40
Alternative investments	13		13
Cash	5		6
Total	100	%	100	%

Xcel Energy Inc. and PSCo base the investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year.

The following tables present, for each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents (a)	$	23,566	$	—		$	—	$	23,566
Derivatives	—		166			—		166
Government securities	—		43,494			—		43,494
Insurance contracts	—		45,075			—		45,075
Corporate bonds	—		48,527			—		48,527
Asset-backed securities	—		3,240			—		3,240
Mortgage-backed securities	—		10,071			—		10,071
Commingled funds	—		252,790			—		252,790
Other	—		(1,647		)	—		(1,647		)
Total	$	23,566	$	401,716		$	—	$	425,282

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents (a)	$	18,202	$	—		$	—	$	18,202
Derivatives	—		(370		)	—		(370		)
Government securities	—		52,028			—		52,028
Insurance contracts	—		47,029			—		47,029
Corporate bonds	—		46,186			—		46,186
Asset-backed securities	—		2,991			—		2,991
Mortgage-backed securities	—		21,593			—		21,593
Commingled funds	—		265,620			—		265,620
Other	—		(15,086		)	—		(15,086		)
Total	$	18,202	$	419,991		$	—	$	438,193

^(a)  Includes restricted cash of $0.9 million and $0.6 million at Dec. 31, 2014 and 2013, respectively.

For the year ended Dec. 31, 2014 there were no assets transferred in or out of Level 3. The following tables present the changes in PSCo’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013 and 2012:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)		Purchases, Issuances and Settlements, Net		Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	670	$	—	$	—	$	—	$	(670	)	$	—
Mortgage-backed securities	35,394		—		—		—		(35,394		)	—
Total	$	36,064	$	—	$	—	$	—	$	(36,064	)	$	—

^(a)  Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2012
Asset-backed securities	$	6,941	$	(293	)	$	1,669		$	(7,647	)	$	—	$	670
Mortgage-backed securities	24,038		(641		)	3,429			8,568			—		35,394
Private equity investments	479		—			(65		)	(414		)	—		—
Real estate	144		—			35			(179		)	—		—
Total	$	31,602	$	(934	)	$	5,068		$	328		$	—	$	36,064

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table:

(Thousands of Dollars)	2014			2013
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	508,971		$	599,831
Service cost	1,915			2,564
Interest cost	23,704			22,210
Medicare subsidy reimbursements	1,753			923
Plan amendments	—			(14,571		)
Plan participants’ contributions	4,625			4,589
Actuarial gain	(63,130		)	(76,889		)
Benefit payments	(34,085		)	(29,686		)
Obligation at Dec. 31	$	443,753		$	508,971

(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	438,193		$	425,917
Actual return on plan assets	11,060			30,390
Plan participants’ contributions	4,625			4,589
Employer contributions	5,489			6,983
Benefit payments	(34,085		)	(29,686		)
Fair value of plan assets at Dec. 31	$	425,282		$	438,193

(Thousands of Dollars)	2014			2013
Funded Status at Dec. 31:
Funded status (a)	$	(18,471	)	$	(70,778	)

^(a)  Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.

(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	56,823		$	107,232
Prior service credit	(40,189		)	(46,436		)
Total	$	16,634		$	60,796

(Thousands of Dollars)	2014		2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	—	$	8,798
Noncurrent regulatory assets	16,634		51,998
Total	$	16,634	$	60,796

Measurement date Dec. 31, 2014 Dec. 31, 2013

	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.08	%	4.82	%
Mortality table	RP 2014		RP 2000
Health care costs trend rate — initial	6.50	%	7.00	%

Effective Jan. 1, 2015, the initial medical trend rate was decreased from 7.0 percent to 6.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is four years. Xcel Energy Inc. and PSCo base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

A one-percent change in the assumed health care cost trend rate would have the following effects on PSCo:

	One-Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	45,581	$	(38,371	)
Service and interest components	3,028		(2,488		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes PSCo, contributed $17.1 million, $17.6 million and $47.1 million during 2014, 2013 and 2012, respectively, of which $5.5 million, $7.0 million and $27.5 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12.8 million during 2015, of which amounts attributable to PSCo will be zero.

Plan Amendments — In 2014 there were no plan amendments made which affected the projected benefit obligation. The 2013 decrease of the projected Xcel Energy and PSCo postretirement health and welfare benefit obligation for plan amendments is due to changes in the participant co-pay structure for certain retiree groups.

Benefit Costs — The components of PSCo’s net periodic postretirement benefit costs were:

(Thousands of Dollars)	2014			2013			2012
Service cost	$	1,915		$	2,564		$	2,825
Interest cost	23,704			22,210			24,527
Expected return on plan assets	(30,214		)	(29,227		)	(25,056		)
Amortization of transition obligation	—			785			11,004
Amortization of prior service credit	(6,247		)	(7,666		)	(5,150		)
Amortization of net loss	6,434			13,699			10,930
Net periodic postretirement benefit (credit) cost	(4,408		)	2,365			19,080
Additional cost recognized due to effects of regulation	—			—			3,891
Net benefit (credit) cost recognized for financial reporting	$	(4,408	)	$	2,365		$	22,971

	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.82	%	4.10	%	5.00	%
Expected average long-term rate of return on assets	7.18		7.11		6.75

In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs.

Projected Benefit Payments

The following table lists PSCo’s projected benefit payments for the pension and postretirement benefit plans:

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2015	$	74,237	$	32,300	$	2,532	$	29,768
2016	77,804		32,991		2,692		30,299
2017	77,126		33,328		2,863		30,465
2018	80,003		34,146		3,033		31,113
2019	82,472		34,053		3,192		30,861
2020-2024	423,835		165,560		18,053		147,507

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Commitments and Contingencies, Removal Costs (Details) (Plant Removal Costs, USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 366	$ 359

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Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2014

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 Dec. 31, 2014
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	1
Maximum amount outstanding	21
Weighted average interest rate, computed on a daily basis	0.28		%
Weighted average interest rate at period end	N/A

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	4.2			0.1			0.3
Maximum amount outstanding	97			12			8
Weighted average interest rate, computed on a daily basis	0.25		%	0.36		%	0.33		%
Weighted average interest rate at period end	N/A			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 borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2014
Borrowing limit	$	700
Amount outstanding at period end	382
Average amount outstanding	292
Maximum amount outstanding	393
Weighted average interest rate, computed on a daily basis	0.37		%
Weighted average interest rate at period end	0.65

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	382			—			154
Average amount outstanding	167			38			8
Maximum amount outstanding	393			332			165
Weighted average interest rate, computed on a daily basis	0.31		%	0.34		%	0.33		%
Weighted average interest rate at period end	0.65			N/A			0.35

Letters of Credit— PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 2014 and 2013, there was $6.4 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 credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Amended Credit Agreement —In October 2014, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an extension of maturity from July 2017 to October 2019. The borrowing limit for PSCo remained at $700 million.

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

Other features of PSCo’s credit facility include:

• PSCo may increase its credit facility by up to $100 million.

• The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. PSCo was in compliance as its debt-to-total capitalization ratio was 47 percent and 45 percent at Dec. 31, 2014 and 2013, respectively. If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

• The credit facility has a cross-default provision that provides PSCo will be in default on its borrowings under the facility if PSCo or any of its subsidiaries whose total assets exceed 15 percent of PSCo’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

• The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.

• The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.

At Dec. 31, 2014, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	388.4	$	311.6

^(a)  These credit facilities have been amended to extend the maturity to 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 Dec. 31, 2014 and 2013.

Long-Term Borrowings

Generally, all real and personal property of PSCo is subject to the liens of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

In March 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044. In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023, and $250 million of 3.95 percent first mortgage bonds due March 15, 2043.

During the next five years, PSCo has long-term debt maturities of $130 million, $300 million and $400 million due in 2017, 2018 and 2019, respectively.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $26.5 million and $37.0 million, net of amortization, at Dec. 31, 2014 and 2013, respectively.  PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend Restrictions —PSCo’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

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Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) (Pension Plans, USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 1,103,865	$ 1,067,057	$ 1,055,308
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	119,553	77,463
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	915,692	925,016
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	68,620	64,578	82,991	94,157
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	82,486	42,721
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	82,486	42,721
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Derivatives
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	508	14,755
Derivatives | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Derivatives | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	508	14,755
Derivatives | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	180,912	125,891
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	180,912	125,891
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	115,593	183,078
Corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	115,593	183,078
Corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1,360	2,356
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1,360	2,356
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0	4,604	9,824
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,997	5,267	12,058
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,997	5,267
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0	12,058	23,614
Common stock
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	37,067	34,742
Common stock | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	37,067	34,742
Common stock | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Common stock | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	50,210	49,022
Private equity investments | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	50,210	49,022	47,056	49,489
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	629,439	582,722
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	629,439	582,722
Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	18,410	15,556	19,273
Real estate | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	18,410	15,556	19,273	11,230
Securities lending collateral obligation and other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(16,117)	10,947
Securities lending collateral obligation and other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Securities lending collateral obligation and other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(16,117)	10,947
Securities lending collateral obligation and other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0

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Accounting Pronouncements

12 Months Ended

Dec. 31, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

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

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Selected Balance Sheet Data

12 Months Ended

Dec. 31, 2014

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	346,007		$	351,180
Less allowance for bad debts	(23,122		)	(22,505		)
	$	322,885		$	328,675

(Thousands of Dollars)	Dec. 31, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	55,491	$	53,127
Fuel	80,963		86,062
Natural gas	102,525		98,818
	$	238,979	$	238,007

(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	10,927,867		$	10,177,056
Natural gas plant	3,210,242			2,757,605
Common and other property	827,708			762,916
Plant to be retired (a)	71,534			101,279
Construction work in progress	828,620			952,469
Total property, plant and equipment	15,865,971			14,751,325
Less accumulated depreciation	(4,239,015		)	(4,008,928		)
	$	11,626,956		$	10,742,397

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

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Preferred Stock

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Preferred Stock

Preferred Stock

PSCo has authorized the issuance of preferred stock.

Preferred Shares Authorized	Par Value		Preferred Shares Outstanding
10,000,000	$	0.01	None

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Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) (Postretirement Benefit Plan)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Postretirement Health Care Benefits [Abstract]
Amortization period for unrecognized accumulated postretirement benefit obligation (in years)	20 years
Target pension asset allocations (in hundredths)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (in hundredths)	25.00%	41.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (in hundredths)	57.00%	40.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (in hundredths)	13.00%	13.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (in hundredths)	5.00%	6.00%

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Commitments and Contingencies, Legal Contingencies (Details) (USD $)	3 Months Ended								12 Months Ended			13 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2001
Legal Contingencies [Abstract]
Sales to the City of Seattle	$ 1,136,791,000	$ 1,049,111,000	$ 993,704,000	$ 1,203,543,000	$ 1,074,442,000	$ 1,044,300,000	$ 966,429,000	$ 1,117,457,000	$ 4,383,149,000	$ 4,202,628,000	$ 3,969,293,000
Pacific Northwest FERC Refund Proceeding [Member]
Legal Contingencies [Abstract]
Accrual for legal contingency	0								0
Minimum amount of damages claimed by plaintiff	34,000,000								34,000,000
Sales to the City of Seattle												50,000,000
Estimated City of Seattle's claim for refunds not including interest	$ 28,000,000								$ 28,000,000
Number of factors considered in assessment									2

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Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2014
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1				$ 425,282
Fair value of plan assets at Dec. 31	438,193		425,917	425,282
Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	36,064		31,602	0
Net realized gains (losses)	0		(934)
Net unrealized gains (losses)	0		5,068
Purchases, issuances and settlements, net	0		328
Transfers in (out) of Level 3	(36,064)	[1]	0
Fair value of plan assets at Dec. 31	0		36,064	0
Asset-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1				3,240
Fair value of plan assets at Dec. 31	2,991		670	3,240
Asset-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	670		6,941	0
Net realized gains (losses)	0		(293)
Net unrealized gains (losses)	0		1,669
Purchases, issuances and settlements, net	0		(7,647)
Transfers in (out) of Level 3	(670)	[1]	0
Fair value of plan assets at Dec. 31	0		670	0
Mortgage-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1				10,071
Fair value of plan assets at Dec. 31	21,593			10,071
Mortgage-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	35,394		24,038	0
Net realized gains (losses)	0		(641)
Net unrealized gains (losses)	0		3,429
Purchases, issuances and settlements, net	0		8,568
Transfers in (out) of Level 3	(35,394)	[1]	0
Fair value of plan assets at Dec. 31	0		35,394	0
Private equity investments | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1			479
Net realized gains (losses)			0
Net unrealized gains (losses)			(65)
Purchases, issuances and settlements, net			(414)
Transfers in (out) of Level 3			0
Fair value of plan assets at Dec. 31			0
Real estate | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1			144
Net realized gains (losses)			0
Net unrealized gains (losses)			35
Purchases, issuances and settlements, net			(179)
Transfers in (out) of Level 3			0
Fair value of plan assets at Dec. 31			$ 0

[1] Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 9.1	$ 8.7	$ 8.6

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Schedule II, Valuation and Qualifying Accounts (Details) (Allowance for Bad Debts, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for Bad Debts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1	$ 22,505		$ 21,918		$ 24,698
Charged to costs and expenses	17,005		16,784		16,323
Charged to other accounts	6,240	[1]	7,005	[1]	7,648	[1]
Deductions from reserves	22,628	[2]	23,202	[2]	26,751	[2]
Balance at Dec. 31	$ 23,122		$ 22,505		$ 21,918

[1] Recovery of amounts previously written off.

[2] Principally bad debts written off.

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Joint Ownership of Generation, Transmission and Gas Facilities (Tables)

12 Months Ended

Dec. 31, 2014

Joint Ownership of Generation, Transmission and Gas Facilities [Abstract]

Investments in Jointly Owned Generation, Transmission and Gas Facilities

Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2014:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	98,145	$	66,333	$	1,405	75.5	%
Hayden Unit 2	121,571		59,999		8,867		37.4
Hayden Common Facilities	37,049		16,928		135		53.1
Craig Units 1 and 2	59,860		35,573		3,013		9.7
Craig Common Facilities 1, 2 and 3	36,890		17,735		527		6.5
Comanche Unit 3	883,971		81,748		64		66.7
Comanche Common Facilities	23,624		1,051		308		82.0
Electric Transmission:
Transmission and other facilities, including substations	151,301		60,847		1,730		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	16,278		5,594		—		60.0
Total	$	1,428,689	$	345,808	$	16,049

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Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Amount outstanding at period end	382,000	$ 0
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	6,400
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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Other Income, Net

12 Months Ended

Dec. 31, 2014

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

Other income, net for the years ended Dec. 31 consisted of the following:

(Thousands of Dollars)	2014			2013			2012
Interest income	$	1,470		$	1,761		$	3,603
Other nonoperating income	3,601			2,603			2,233
Insurance policy expense	(806		)	(1,228		)	(1,100		)
Other income, net	$	4,265		$	3,136		$	4,736

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Segments and Related Information

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Segment Information

Segments and Related Information

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

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

• PSCo’s regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s commodity trading operations.

• PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado.

• Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities.

Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from 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.

The accounting policies of the segments are the same as those described in Note 1.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2014
Operating revenues (a)	$	3,125,937	$	1,215,324	$	41,888		$	—		$	4,383,149
Intersegment revenues	339		180		—			(519		)	—
Total revenues	$	3,126,276	$	1,215,504	$	41,888		$	(519	)	$	4,383,149
Depreciation and amortization	$	285,968	$	89,186	$	4,048		$	—		$	379,202
Interest charges and financing costs	124,118		29,987		535			—			154,640
Income tax expense (benefit)	208,095		50,874		(15,378		)	—			243,591
Net Income	349,793		84,324		21,071			—			455,188

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2013
Operating revenues (a)	$	3,081,171	$	1,080,703	$	40,754		$	—		$	4,202,628
Intersegment revenues	302		110		—			(412		)	—
Total revenues	$	3,081,473	$	1,080,813	$	40,754		$	(412	)	$	4,202,628
Depreciation and amortization	$	280,972	$	75,510	$	3,935		$	—		$	360,417
Interest charges and financing costs	129,787		30,604		554			—			160,945
Income tax expense (benefit)	220,356		42,294		(11,910		)	—			250,740
Net income	368,586		69,682		15,115			—			453,383

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2012
Operating revenues (a)	$	2,969,899	$	962,435	$	36,959		$	—		$	3,969,293
Intersegment revenues	282		90		—			(372		)	—
Total revenues	$	2,970,181	$	962,525	$	36,959		$	(372	)	$	3,969,293
Depreciation and amortization	$	267,944	$	66,983	$	3,900		$	—		$	338,827
Interest charges and financing costs	145,641		33,430		618			—			179,689
Income tax expense (benefit)	212,347		27,968		(7,771		)	—			232,544
Net income	387,724		60,003		10,349			—			458,076

^(a)  Operating revenues include $14 million, $13 million and $14 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012, respectively. See Note 16 for further discussion of related party transactions by reportable segment.

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 15,865,971		$ 14,751,325
Less accumulated depreciation	(4,239,015)		(4,008,928)
Property, plant and equipment, net	11,626,956		10,742,397
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	10,927,867		10,177,056
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	3,210,242		2,757,605
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	827,708		762,916
Plant to be retired
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	71,534	[1]	101,279	[1]
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 828,620		$ 952,469

[1] As a result of the CPUC’s 2010 approval of PSCo’s CACJA compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation.

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2014 and 2013 were:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	32,195	$	500,889	$	45,504	$	447,752
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		141,214		—		116,477
Contract valuation adjustments (b)	10	Term of related contract	8,901		12,999		3,620		16,474
Depreciation differences	1	One to seventeen years	10,700		104,743		10,917		95,844
Net AROs (c)	1, 12	Plant lives	—		46,213		—		39,986
Conservation programs (d)	1, 11	One to five years	10,198		10,906		13,883		19,430
Gas pipeline inspection costs	12	One to four years	5,416		3,611		5,416		14,978
Renewable resources and environmental initiatives	12	One to two years	—		—		22,325		—
Purchased power contract costs	12	Term of related contract	858		29,596		—		30,069
Losses on reacquired debt	4	Term of related debt	1,426		8,378		1,572		9,804
Recoverable purchased natural gas and electric energy costs	1	Less than one year	18,410		—		18,022		—
Property tax		One to three years	28,024		31,429		18,427		30,626
Other		Various	3,992		13,995		10,477		4,597
Total regulatory assets			$	120,120	$	903,973	$	150,163	$	826,037

^(a)  Includes $4.5 million and $4.1 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2014 and 2013, respectively.

^(b)  Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

^(c)  Includes amounts recorded for future recovery of AROs.

^(d)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Regulatory Liabilities

The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2014 and 2013 were:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	366,359	$	—	$	359,387
Deferred electric, gas and steam production costs	1	Less than one year	24,035		—		33,247		—
Investment tax credit deferrals	1, 7	Various	—		22,225		—		24,038
Deferred income tax adjustment	1	Various	—		18,672		—		18,770
Conservation programs (a)	1, 11	Less than one year	32,226		—		12,188		—
Renewable resources and environmental initiatives	11, 12	Various	3,308		10,376		—		1,412
Low income discount program		Less than one year	1,680		—		4,084		—
Gain from asset sales		One to three years	316		4		1,687		368
PSCo earnings test	11	One to two years	57,127		42,819		22,892		19,203
Gas pipeline inspection costs	12	One to four years	13,970		642		—		—
Other		Various	1,797		3,324		5,401		1,512
Total regulatory liabilities			$	134,459	$	464,421	$	79,499	$	424,690

^(a)  Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative instruments:
Net fair value (decrease) increase, tax	$ (43)	$ 5	$ (5,708)
Reclassification of losses (gains) to net income, tax	$ (287)	$ (294)	$ (725)

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Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	$ (23,338)
Accumulated other comprehensive income (loss) at end of period	(23,878)		(23,338)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	751,786		762,322		742,975
Total, pre-tax	(698,779)		(704,123)		(690,620)
Income tax expense (benefit)	243,591		250,740		232,544
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	(23,338)		(22,871)
Other comprehensive income (loss) before reclassifications	(72)		9
(Gains) losses reclassified from net accumulated other comprehensive loss	(468)		(476)
Net current period other comprehensive income (loss)	(540)		(467)
Accumulated other comprehensive income (loss) at end of period	(23,878)		(23,338)
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	(755)		(770)
Income tax expense (benefit)	287		294
Total, net of tax	(468)		(476)
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	(730)	[1]	(730)	[1]
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	$ (25)	[2]	$ (40)	[2]

[1] Included in interest charges.

[2] Included in O&M expenses

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	$ (11,480)		$ (11,301)
Total long-term debt	3,890,229		3,872,643
Less current maturities	8,178		282,143
Long-term Debt and Capital Lease Obligations	3,882,051		3,590,500
Common Stockholder's Equity
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2014 and 2013, respectively.	0		0
Additional paid in capital	3,522,788		3,441,290
Retained earnings	1,386,929		1,384,047
Accumulated other comprehensive loss	(23,878)		(23,338)
Total common stockholder’s equity	4,885,839		4,801,999
First Mortgage Bonds | Series Due April 1, 2014
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	0		275,000
First Mortgage Bonds | Series Due Sept. 1, 2017
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	129,500	[1]	129,500	[1]
First Mortgage Bonds | Series Due Aug. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	300,000		300,000
First Mortgage Bonds | Series Due June 1, 2019
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	400,000		400,000
First Mortgage Bonds | Series Due Nov. 15, 2020
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	400,000		400,000
First Mortgage Bonds | Series Due Sept. 15, 2022
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	300,000		300,000
First Mortgage Bonds | Series Due March 15, 2023
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	250,000		250,000
First Mortgage Bonds | Series Due Sept. 1, 2037
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	350,000		350,000
First Mortgage Bonds | Series Due Aug. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	300,000		300,000
First Mortgage Bonds | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	250,000		250,000
First Mortgage Bonds | Series Due Sept. 15, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	500,000		500,000
First Mortgage Bonds | Series Due March 15, 2043
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	250,000		250,000
First Mortgage Bonds | Series Due March 15, 2044
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	300,000		0
Capital Lease Obligations
Schedule of Capitalization, Long-term Debt [Line Items]
Capital lease obligations	$ 172,209		$ 179,444

[1] Pollution control financing.

XML

Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2014
Commingled funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	1 day
Commingled funds | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days
Real estate funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	45 days
Real estate funds | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days

XML

Commitments and Contingencies, Environmental Contingencies (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Apr. 30, 2012 MW	Jun. 30, 2014	Dec. 31, 2010 Kiln Group Boiler	Dec. 31, 2014 Parts-per-million	Dec. 31, 2013
Greenhouse Gas New Source Performance Standard for Modified and Reconstructed Power Plants
Environmental Requirements [Abstract]
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants (in hundredths)		50.00%
Electric Generating Unit Mercury And Air Toxics Standards Rule
Environmental Requirements [Abstract]
Generating capacity (in MW)	25
Number of years before affected facilities must demonstrate compliance, low end of range	3 years
Number of years before affected facilities must demonstrate compliance, high end of range	4 years
Regional Haze Rules
Environmental Requirements [Abstract]
Number of environmental groups who petitioned the U.S. Department of the Interior			2
Number of coal-fired boilers in Colorado			12
Number of coal-fired cement kilns in Colorado			1
National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of hours the NAAQS for Ozone is based upon (in hours)				8
Current level of air quality concentrations (in parts per million)				0.075
Proposed level of air quality concentrations (in parts per million)				0.070
Lowest proposed level of air quality concentrations that the EPA is taking comment on (in parts per million)				0.060
Capital Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Amount spent on installation of emission controls				272.6
Liability for estimated cost to comply with regulation				84.6
Minimum | National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Proposed level of air quality concentrations (in parts per million)				0.065
Maximum [Member] | National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Proposed level of air quality concentrations (in parts per million)				0.070
Other MGP Sites
Site Contingency [Line Items]
Number of identified MGP sites under current investigation and/or remediation				2
Liability for estimated cost of remediating sites				1.8	$ 1.2

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014 MWh		Dec. 31, 2013 MWh
Credit Concentration Risk [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	10
Credit Concentration Risk [Member] | Investment Grade Ratings from Standard & Poor's, Moody's, or Fitch Ratings [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	7
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	35.3
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	43.00%
Credit Concentration Risk [Member] | No Investment Grade Ratings from External Credit Rating Agencies [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	3
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	31.0
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	38.00%
Electric Commodity [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount	0	[1],[2]	326,000	[1],[2]
Natural Gas Commodity [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount	735,000	[1],[2]	6,398,000	[1],[2]
Vehicle Fuel Commodity [Member]
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount	127,000	[1],[2]	217,000	[1],[2]

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

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

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 4 for further discussion.

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Thousands of Dollars)	2014		2013		2012
Operating revenues:
Electric	$	9,614	$	8,136	$	9,271
Other	4,441		4,441		4,441
Operating expenses:
Purchased power	23		1,331		6,539
Other operating expenses — paid to Xcel Energy Services Inc.	454,250		375,766		316,548
Interest expense	158		132		114
Interest income	61		273		122

Accounts receivable and payable with affiliates at Dec. 31 were:

	2014				2013
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	6,706	$	18,065	$	—
NSP-Wisconsin	22		—		8		—
SPS	5,803		—		1,056		—
Other subsidiaries of Xcel Energy Inc.	45,017		40,030		7		45,902
	$	50,842	$	46,736	$	19,136	$	45,902

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset			$ 0
Derivative Asset, Collateral, Obligation to Return Cash, Offset			200,000
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,731,000		6,576,000
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,176,000		6,905,000
Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	5,774,000		6,734,000
Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	18,257,000		23,366,000
Fair Value Measured on a Recurring Basis | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,000		4,861,000
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			40,000
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			1,480,000
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,000		3,341,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			13,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			13,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	530,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	53,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	583,000		1,399,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			1,399,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	81,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	46,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	35,000
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	33,000		6,137,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			40,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			2,756,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	33,000		3,341,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			13,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			13,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	548,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	53,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	601,000		2,438,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			2,438,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	81,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	46,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	35,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
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 [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	33,000		6,137,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			40,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			2,756,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	33,000		3,341,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			13,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			13,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	548,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	53,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	601,000		2,438,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			2,438,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	81,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	46,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	35,000
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(18,000)	[1]	(1,276,000)	[2]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0	[2]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Assets [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			(1,276,000)	[2]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Assets [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(18,000)	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0	[2]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0	[2]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(18,000)	[1]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	[1]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(18,000)	[1]	(1,039,000)	[2]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Liabilities [Member] | Other Derivative Instruments [Member] | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			(1,039,000)	[2]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	[1]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Vehicle Fuel And Other Commodity [Member] | Cash Flow Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	[1]
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Noncurrent Liabilities [Member] | Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	[1]
Fair Value, Measurements, Nonrecurring [Member] | Other Current Assets [Member] | Purchased Power Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,716,000	[3]	1,715,000	[3]
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Assets [Member] | Purchased Power Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,176,000	[3]	6,892,000	[3]
Fair Value, Measurements, Nonrecurring [Member] | Other Current Liabilities [Member] | Purchased Power Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	5,191,000	[3]	5,335,000	[3]
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Liabilities [Member] | Purchased Power Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 18,176,000	[3]	$ 23,366,000	[3]

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

[2] PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[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.

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Other Income, Net (Tables)

12 Months Ended

Dec. 31, 2014

Other Income and Expenses [Abstract]

Other Income, Net

Other income, net for the years ended Dec. 31 consisted of the following:

(Thousands of Dollars)	2014			2013			2012
Interest income	$	1,470		$	1,761		$	3,603
Other nonoperating income	3,601			2,603			2,233
Insurance policy expense	(806		)	(1,228		)	(1,100		)
Other income, net	$	4,265		$	3,136		$	4,736

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Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

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 Dec. 31, 2014, accumulated other comprehensive losses related to interest rate derivatives included an immaterial amount 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 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 Dec. 31, 2014, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016.  PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI 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 years ended Dec. 31, 2014 and 2013.

At Dec. 31, 2014, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net 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 Dec. 31:

(Amounts in Thousands)(a)(b)	2014	2013
MWh of electricity	—	326
MMBtu of natural gas	735	6,398
Gallons of vehicle fuel	127	217

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

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

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 Dec. 31, 2014, seven of PSCo’s 10 most significant counterparties for these activities, comprising $35.3 million or 43 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  The remaining three most significant counterparties, comprising $31.0 million or 38 percent of this credit exposure at Dec. 31, 2014, were not rated by these agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.  All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:

(Thousands of Dollars)	2014			2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,338	)	$	(22,871	)	$	(12,377	)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(72		)	9			(9,311		)
After-tax net realized gains on derivative transactions reclassified into earnings	(468		)	(476		)	(1,183		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23,878	)	$	(23,338	)	$	(22,871	)

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2014, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)				Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—	$	(730	)	(a)	$	—			$	—
Vehicle fuel and other commodity	(115		)	—		(25		)	(b)	—				—
Total	$	(115	)	$	—	$	(755	)		$	—			$	—
Other derivative instruments
Natural gas commodity	$	—		$	451	$	—			$	(4,631	)	(e)	$	(9,850	)	(e)
Total	$	—		$	451	$	—			$	(4,631	)		$	(9,850	)

	Year Ended Dec. 31, 2013
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains)Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	(730	)	(a)	$	—		$	—
Vehicle fuel and other commodity	14		—			(40		)	(b)	—			—
Total	$	14	$	—		$	(770	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—	$	(4,001	)	$	—			$	4,340	(e)	$	5,850	(d)
Total	$	—	$	(4,001	)	$	—			$	4,340		$	5,850

	Year Ended Dec. 31, 2012
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(15,082	)	$	—	$	(1,819	)	(a)	$	—		$	—
Vehicle fuel and other commodity	63			—		(89		)	(b)	—			—
Total	$	(15,019	)	$	—	$	(1,908	)		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—	$	—			$	—		$	2		(c)
Natural gas commodity	—			7,727		—				61,820		(e)	(137		)	(d)
Total	$	—		$	7,727	$	—			$	61,820		$	(135	)

^(a)  Amounts are recorded to interest charges.

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

^(e)  Amounts for the year ended Dec. 31, 2012 included $5.0 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.  Such losses for the years ended Dec. 31, 2014 and 2013 were immaterial.  The remaining settlement losses for the years ended Dec. 31, 2014, 2013 and 2012 relate to natural gas operations and are recorded to cost of natural gas sold and transported.  These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2014, 2013 and 2012.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features—Contract provisions for derivative instruments that PSCo enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale 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 Dec. 31, 2014, there were no derivative instruments with contract provisions that required the posting of collateral or settlement of the contracts. If the credit ratings of PSCo were downgraded below investment grade, derivative instruments reflected in a $1.4 million gross liability position on the consolidated balance sheets at Dec. 31, 2013, would have required PSCo to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $1.4 million at Dec. 31, 2013. At Dec. 31, 2013, there was no collateral posted on these specific contracts.

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

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

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

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, PSCo qualified these contracts under the normal purchase exception.  Based 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 Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:

	Dec. 31, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	40	$	—	$	40	$	—		$	40
Other derivative instruments:
Commodity trading	—		2,756		—		2,756		(1,276		)	1,480
Natural gas commodity	—		3,341		—		3,341		—			3,341
Total current derivative assets	$	—	$	6,137	$	—	$	6,137	$	(1,276	)	4,861
PPAs (a)												1,715
Current derivative instruments												$	6,576
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	13	$	—	$	13	$	—		$	13
Total noncurrent derivative assets	$	—	$	13	$	—	$	13	$	—		13
PPAs (a)												6,892
Noncurrent derivative instruments												$	6,905
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	$	1,399
Total current derivative liabilities	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	1,399
PPAs (a)												5,335
Current derivative instruments												$	6,734
Noncurrent derivative liabilities
PPAs (a)												23,366
Noncurrent derivative instruments												$	23,366

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

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013.  At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2014, 2013 and 2012.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2014, 2013 and 2012.

Fair Value of Long-Term Debt

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

	2014				2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,890,229	$	4,328,968	$	3,872,643	$	4,059,661

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 Dec. 31, 2014 and 2013, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.