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, 2015

or

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

Commission File Number: 001-3280

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

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

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 ¨ 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. ¨ 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. 22, 2016, 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

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2016 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2016. Such information set forth under such heading is incorporated herein by this reference hereto.

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).

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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	7
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	13
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	81
Item 9A — Controls and Procedures	81
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	82
PART IV
Item 15 — Exhibits, Financial Statement Schedules	83
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
CPP	Clean Power Plan
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
ITC	Investment tax credit
JOA	Joint operating agreement
MGP	Manufactured gas plant
MISO	Midcontinent Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services
MYP	Multi-year plan
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
O&M	Operating and maintenance
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
RPS	Renewable portfolio standards
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services
Wexpro	Wexpro Development Company
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 2015.  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 1.4 million customers.  All of PSCo’s retail electric operating revenues were derived from operations in Colorado during 2015.  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 business services.  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 40 percent to 50 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 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; improving customer experience; 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. PSCo is authorized to make wholesale electric sales at market-based prices to customers outside its balancing authority area.

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 on a quarterly basis beginning in January 2015.

• 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.

• 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 — The CACJA recovers 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.

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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 2018.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2016, assuming normal weather conditions, is as follows:

	System Peak Demand (in MW)
	2013	2014	2015	2016 Forecast
PSCo	6,678	6,152	6,284	6,493

The peak demand for PSCo’s system typically occurs in the summer. The 2015 system peak demand for PSCo occurred on Aug. 5, 2015. The 2014 system peak demand was lower due to reduced wholesale loads and cooler summer weather. The forecast of 2016 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— 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 became operational in 2015. These additional PPAs bring the installed wind capacity on PSCo’s system in Colorado to 2,560 MW;

• The addition of 170 MW of utility-scale solar generation PPAs, of which 50 MW became operational in 2015 and the remaining 120 MW of utility-scale solar generation is expected to be operational by mid-2016. PSCo has approximately 80 MW of utility-scale solar and approximately 258 MW of customer-sited solar generation;

• The addition of 317 MW of natural gas fired generation PPAs 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.

In addition, PSCo continues to execute on the remaining aspects of CACJA compliance including the recent completion of the new natural gas fired combined cycle unit at Cherokee and the ongoing addition of emissions controls at the Pawnee and Hayden stations. PSCo also retired the Cherokee Unit 3 in August 2015 and expects to retire Valmont Unit 5 coal-fired power plant by the end of 2017.

Brush, Colo. to Castle Pines, Colo. 345 KV Transmission Line — In April 2015, the CPUC granted a CPCN to construct a new 345 KV transmission line originating from Pawnee generating station, near Brush, Colo. and terminating at the Daniels Park substation, near Castle Pines, Colo. to be placed in service by 2022. The estimated project cost is $178 million. The CPUC’s decision requires that project construction begin no earlier than May 2020.

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

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

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

Colorado “Our Energy Future” Plan —In January 2016, PSCo introduced the “Our Energy Future” Plan in Colorado. This proposal ties together innovative technology, economic development and customer initiatives to give customers more control over their energy use, prepare for the future energy demands of the state and keep rates competitive. The key components of the plan, which includes several filings with the CPUC, are as follows:

• Two Innovative Clean Technology pilot programs in partnership with leading companies to address electric battery efficiency and reliability including demonstrations to test microgrids and battery technologies for integration of distributed resources;

• Alignment of PSCo’s pricing in a more fair and equitable manner for Colorado customers;

• Introduction of Solar*Connect®, a new, cost-based program that will offer customers a choice to sign up for 100 percent solar power and add an incremental 50 MW of solar generation;

• Investing in natural gas reserves to take advantage of historically low natural gas prices by locking in current costs to provide long-term stable rates for customers;

• Exploring opportunities for up to 1,000 MW of additional renewable resources to be presented later this year for consideration by the CPUC; and

• Presenting an intelligent grid proposal later this year focusing on interactive meter technology that will improve customer choice and control of their energy use. 

RES Compliance Plan — Colorado law mandates that at least 20 percent of PSCo’s energy sales are supplied by renewable energy through 2019, with the percentage increasing to 30 percent by 2020 and includes a distributed generation standard. PSCo is in compliance with the RES as of Dec. 31, 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
2015	$	1.75	75	%	$	3.89	25	%	$	2.29
2014	1.82		75		5.32		25		2.68
2013	1.84		80		4.86		20		2.45

The cost of natural gas in 2015 decreased due to lower wholesale commodity prices.

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

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Fuel Sources

Coal— PSCo normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2015 and 2014 were approximately 49 and 36 days usage, respectively. At Dec. 31, 2015, milder weather, purchase commitments and resolution of railcar congestion resulted in coal inventories being slightly above optimal levels. PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2015 and 2014, PSCo’s coal requirements for existing plants were approximately 10.5 million tons and 10.3 million tons, respectively. The estimated coal requirements for 2016 are approximately 10.1 million tons.

PSCo has contracted for coal supply to provide 96 percent of its estimated coal requirements in 2016, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 90 percent of requirements for the first year, 60 percent of requirements in year two, and 30 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 and 86 percent of its coal requirements in 2016 and 2017, respectively. 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 10 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, 2015, PSCo’s commitments related to gas supply contracts, which expire in various years from 2016 through 2023, were approximately $750 million and commitments related to gas transportation and storage contracts, which expire in various years from 2016 through 2060, were approximately $684 million.

• At Dec. 31, 2014, PSCo’s commitments related to gas supply contracts were approximately $902 million and commitments related to gas transportation and storage contracts were approximately $685 million.

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

PSCo Natural Gas Reserves Investments — In January 2016, PSCo filed a request with the CPUC for approval of a long-term natural gas procurement and price hedging framework. Under the proposal, a wholly-owned subsidiary of PSCo, PSCo Gas Reserves Company (PGRCo), will be formed to partner with Wexpro, a subsidiary of Questar Corporation, to acquire, develop and operate natural gas producing properties on a 50/50 joint basis, with production recovered under cost of service pricing through PSCo’s GCA. The CPUC has 240 days to review the proposed framework. If approved, PGRCo may invest up to approximately $500 million in gas properties over 10 years, which is not reflected in the current base capital expenditures forecast.

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

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

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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, 2015, PSCo was in compliance with mandated RPS, which require generation from renewable resources of 20 percent of electric retail sales.

• Renewable energy comprised 21.9 percent and 21.4 percent of PSCo’s total energy for 2015 and 2014, respectively;

• Wind energy comprised 19.4 percent and 18.9 percent of the total energy for 2015 and 2014, respectively; and

• Hydroelectric, biomass and solar power comprised approximately 2.6 percent and 2.5 percent of the total energy for 2015 and 2014.

PSCo also offers customer-focused renewable energy initiatives. Windsource® allows customers to purchase a portion or all of their electricity from renewable sources. In 2015, the number of customers utilizing Windsource increased to approximately 45,000 from 41,000 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 29,500 PV systems with approximately 258 MW of aggregate capacity and over 24,000 PV systems with approximately 221 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2015 and 2014, respectively. Additionally, 24 community solar gardens with 16.6 MW of capacity and 14 gardens with 9.6 MW of capacity have been completed in Colorado as of Dec. 31, 2015 and 2014, respectively.

Wind— PSCo acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Colorado. Currently, PSCo has 19 of these agreements in place, with facilities ranging in size from two MW to over 300 MW.

• PSCo had approximately 2,560 MW and 2,340 MW of wind energy on its system at the end of 2015 and 2014, respectively. 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 $42 and $45 in 2015 and 2014, respectively. 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 2015 continued to benefit from improvements in wind technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the Federal PTCs. In December 2015, the Federal PTCs were extended through 2019 with a phase down beginning in 2017.

Wholesale and Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. See Item 7 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 March, 2015, FERC upheld the new ROE methodology and denied rehearing. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC is not expected to issue orders in any litigated ROE complaint proceedings until at least mid-2016.

NERC Critical Infrastructure Protection Requirements — The FERC has approved Version 5 of NERC’s critical infrastructure protection standards, which added additional requirements to strengthen grid security controls. Requirements must be applied by PSCo 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 implementing initiatives to meet the compliance deadlines. The additional cost for compliance is anticipated to be recoverable through rates.

NERC Physical Security Requirements — In November 2014, the FERC approved NERC’s proposed critical infrastructure protection standard related to physical security for bulk electric system facilities. The new standard became enforceable in October 2015 with staggered milestone deliverable dates through 2016.  PSCo has performed an initial risk assessment and is in the process of developing physical security plans in accordance with the requirements of 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
	2015			2014			2013
Electric sales (Millions of KWh)
Residential	9,112			9,009			9,266
Large commercial and industrial	6,596			6,712			6,652
Small commercial and industrial	12,750			12,709			12,716
Public authorities and other	242			241			227
Total retail	28,700			28,671			28,861
Sales for resale	3,581			3,664			4,467
Total energy sold	32,281			32,335			33,328
Number of customers at end of period
Residential	1,218,662			1,202,621			1,187,308
Large commercial and industrial	337			334			328
Small commercial and industrial	158,086			156,809			155,643
Public authorities and other	53,944			53,824			53,724
Total retail	1,431,029			1,413,588			1,397,003
Wholesale	26			23			23
Total customers	1,431,055			1,413,611			1,397,026
Electric revenues (Thousands of Dollars)
Residential	$	1,060,626		$	1,081,092		$	1,083,928
Large commercial and industrial	433,061			462,449			437,556
Small commercial and industrial	1,220,064			1,267,023			1,218,856
Public authorities and other	52,783			54,555			52,676
Total retail	2,766,534			2,865,119			2,793,016
Wholesale	180,716			211,241			228,041
Other electric revenues	168,007			49,577			60,114
Total electric revenues	$	3,115,257		$	3,125,937		$	3,081,171
KWh sales per retail customer	20,055			20,282			20,659
Revenue per retail customer	$	1,933		$	2,027		$	1,999
Residential revenue per KWh	11.64		¢	12.00		¢	11.70		¢
Large commercial and industrial revenue per KWh	6.57			6.89			6.58
Small commercial and industrial revenue per KWh	9.57			9.97			9.59
Total retail revenue per KWh	9.64			9.99			9.68
Wholesale revenue per KWh	5.05			5.77			5.11

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Energy Source Statistics

	Year Ended Dec. 31
	2014			2014			2013
	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	18,601	54	%	18,274	53	%	19,647	56	%
Natural Gas	7,948	23		8,601	25		7,565	22
Wind (a)	6,699	19		6,472	19		6,750	19
Hydroelectric	662	2		617	2		655	2
Other (b)	705	2		294	1		250	1
Total	34,615	100	%	34,258	100	%	34,867	100	%
Owned generation	22,981	66	%	23,023	67	%	22,873	66	%
Purchased generation	11,634	34		11,235	33		11,994	34
Total	34,615	100	%	34,258	100	%	34,867	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 245, 197, and 172 million net KWh for 2015, 2014, and 2013, respectively.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of PSCo are 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 small C&I customer, as a result of improved building construction technologies, higher appliance efficiencies, and conservation. From 2000 to 2015, average annual sales to the typical PSCo residential customer declined 15 percent, while sales to the typical small C&I customer declined 12 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.

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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.

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 2018.

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 2018.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for PSCo was 1,633,493 MMBtu, which occurred on March 4, 2015 and 2,116,747 MMBtu, which occurred on Dec. 30, 2014.

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 1,818,277 MMBtu per day, which includes 854,852 MMBtu of natural gas held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide approximately 43,500 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:

2015	$	3.92
2014	4.91
2013	4.20

The cost of natural gas in 2015 decreased due to lower wholesale commodity prices.

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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, 2015, PSCo was committed to approximately $1.1 billion in such obligations under these contracts, which expire in various years from 2016 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 2015, PSCo purchased natural gas from approximately 32 suppliers.

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

Natural Gas Operating Statistics

	Year Ended Dec. 31
	2015		2014		2013
Natural gas deliveries (Thousands of MMBtu)
Residential	92,001		99,127		100,329
Commercial and industrial	38,405		40,438		40,259
Total retail	130,406		139,565		140,588
Transportation and other	108,860		108,006		109,637
Total deliveries	239,266		247,571		250,225
Number of customers at end of period
Residential	1,254,056		1,240,674		1,228,917
Commercial and industrial	100,389		100,238		100,071
Total retail	1,354,445		1,340,912		1,328,988
Transportation and other	6,936		6,547		6,273
Total customers	1,361,381		1,347,459		1,335,261
Natural gas revenues (Thousands of Dollars)
Residential	$	678,909	$	824,633	$	729,304
Commercial and industrial	257,287		313,821		273,032
Total retail	936,196		1,138,454		1,002,336
Transportation and other	70,470		76,870		78,367
Total natural gas revenues	$	1,006,666	$	1,215,324	$	1,080,703
MMBtu sales per retail customer	96.28		104.08		105.79
Revenue per retail customer	$	691	$	849	$	754
Residential revenue per MMBtu	7.38		8.32		7.27
Commercial and industrial revenue per MMBtu	6.70		7.76		6.78
Transportation and other revenue per MMBtu	0.65		0.71		0.71

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.

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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 solar generation (typically rooftop solar or solar gardens) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. 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.

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. 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 present and future environmental regulations 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, 2015, PSCo had 2,618 full-time employees, of which 2,024 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.

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Oversight of Risk and Related Processes

A key accountability of the Board is the oversight of material risk, and our Board employs an effective process for doing so. As outlined below, management and each Board committee has responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Management broadly considers our business, the utility industry, the domestic and global economies and the environment when identifying, assessing, managing and mitigating risk. 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 and the discussion of the key risks 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 approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of the Company. First, the Board as a whole regularly reviews management’s key risk assessment and analyzes areas of existing and future risks and opportunities. In addition, the Board assigns oversight of certain critical risks to each of its four standing committees to ensure these risks are well understood and given focused oversight by the committee with the most applicable expertise. The Audit Committee is responsible for reviewing the adequacy of risk oversight and affirming that appropriate oversight occurs. New risks are considered and assigned as appropriate during the annual Board and committee evaluation process, and committee charters and annual work plans are updated accordingly. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board for consideration where deemed appropriate to ensure broad Board understanding of the nature of the risk. Finally, the Board conducts an annual strategy session where the Company’s future plans and initiatives are reviewed and confirmed.

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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, shift generation to lower-emitting but potentially more costly facilities, 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 makes operation of the units no longer economical. 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., clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2015, 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 may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO₂, CO₂ and other GHGs, particulates, cooling water intakes, water discharges and ash management.  We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

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

Climate change can create physical and financial risk. Physical risks from climate change can 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 result in 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, whether caused by climate change or otherwise, 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.

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Climate change may impact a region’s economic health which could impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as 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.  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, which could result in cost disallowances, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements and there is no assurance that regulators would allow full recovery of all remaining 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 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.

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. As a result, we frequently need to access 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 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.

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We are subject to credit risks.

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense.  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.

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.

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 most of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions, including mortality tables, 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 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.

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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, 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 anticipated costs.  Therefore, a significant disruption could 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 could have a negative impact on our cash flows and potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and 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.

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

Most electric utility investments are long-lived and are planned to be used for decades. Transmission and generation investments typically have long lead times, and therefore are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. The electric utility sector is undergoing a period of significant change. For example, public policy has driven increases in appliance and lighting efficiency and energy efficient buildings, wider adoption and lower cost of renewable generation and distributed generation, shifts away from coal generation to decrease carbon dioxide emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. These changes introduce additional uncertainty into long term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution.

The resource plans reviewed and approved by our state regulators assume continuation of the traditional utility cost of service model under which utility costs are recovered from customers as they receive the benefit of service. PSCo is engaged in significant and ongoing infrastructure investment programs to accommodate distributed generation and maintain high system reliability. PSCo is also investing in renewable and natural gas-fired generation to reduce our carbon dioxide emissions profile. Early plant retirements could expose us to premature financial obligations, which could result in less than full recovery of all remaining costs. Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts downward pressure on load growth. This could lead to under recovery of costs, excess resources to meet customer demand, and increases in electric rates.

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.

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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 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, 2015, Xcel Energy Inc. and its utility subsidiaries had approximately $12.5 billion of long-term debt and $1.5 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.

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, 2015, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $12.5 million and exposure of $0.1 million. Xcel Energy also had additional guarantees of $41.3 million at Dec. 31, 2015 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 2015, 2014 and 2013 we paid $330.8 million, $433.8 million and $263.9 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.

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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.

The EPA is regulating GHGs from power plants with state plans to achieve the EPA’s goals due by September 2018. Increased public awareness and concern regarding climate change may result in more state, 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 at either the state or federal level in the future. Such regulations could impose substantial costs on our system. International agreements could have an impact to the extent they lead to future federal or state regulations.

The United States continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change (UNFCCC). In December 2015, the 21^st Conference of the Parties to the UNFCCC reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”), with a goal of holding the increase in global average temperature to below 2^o Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5^o Celsius. The Paris Agreement could result in future additional GHG reductions 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.

The form and stringency of GHG regulation in the power sector has become more clear with the finalization of the Clean Power Plan by the EPA. The legality of the Clean Power Plan is being challenged in the courts. In addition, uncertainties remain regarding implementation plans in our states (and the federal plan imposed by the EPA for states who do not submit approvable plans), including what opportunities are available to reduce costs, whether and what type of emission trading will be available, how states will allocate the reduction burden among utilities, what actions are creditable and the indirect impact of carbon regulation on natural gas and coal prices.

An 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 intakes, 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, particularly as it relates to energy trading activities for both electricity and natural gas.  In addition, NERC electric reliability standards and critical infrastructure protection requirements are 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.

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Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. 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 is 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.

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.  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. In addition, we 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, the 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.

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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.

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.

Although commodity prices are currently relatively low, if fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered.  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 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 2015 Net Dependable Capability (MW)
Steam:
Cherokee-Denver, Colo., 1 Unit	Coal	1968	352
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
Combustion Turbine:
Cherokee-Denver, Colo., 3 Units	Natural Gas	2015	576
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	173
Hydro:
Cabin Creek-Georgetown, Colo.
Pumped Storage, 2 Units	Hydro	1967	210
Various locations, 9 Units	Hydro	Various	26
		Total	5,319

^(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.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2015:

Conductor Miles
345 KV	2,630
230 KV	12,553
138 KV	92
115 KV	4,925
Less than 115 KV	75,155

PSCo had 229 electric utility transmission and distribution substations at Dec. 31, 2015.

Natural gas utility mains at Dec. 31, 2015:

Miles
Transmission	2,278
Distribution	22,045

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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 2015 and 2014 were as follows:

(Thousands of Dollars)	2015		2014
First quarter	$	80,650	$	194,022
Second quarter	82,872		96,391
Third quarter	83,672		78,241
Fourth quarter	83,373		83,652

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).

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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.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015 (including the items described under Factors Affecting Results of Operations; 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), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

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

Results of Operations

PSCo’s net income was approximately $466.8 million for 2015, compared with approximately $455.2 million for 2014.  The increase is primarily due to the CACJA rider (partially offset by an electric base rate decrease), as well as a natural gas rate increase (interim, subject to refund) effective in October 2015, lower estimated electric earnings test refunds and the positive impact of weather. These positive factors were partially offset by higher property taxes, depreciation, O&M expenses, interest charges and lower AFUDC.

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)	2015			2014
Electric revenues	$	3,115		$	3,126
Electric fuel and purchased power	(1,247		)	(1,405		)
Electric margin	$	1,868		$	1,721

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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)	2015 vs. 2014
Fuel and purchased power cost recovery	$	(147	)
Retail rate decrease	(37		)
Trading, including REC sales	(10		)
CACJA non-fuel rider	94
Earnings test refunds	74
Estimated impact of weather	11
Firm wholesale	7
Other, net	(3		)
Total decrease in electric revenues	$	(11	)

Electric Margin

(Millions of Dollars)	2015 vs. 2014
CACJA non-fuel rider	$	94
Earnings test refunds	74
Estimated impact of weather	11
Firm wholesale	7
Retail rate decrease	(37		)
Other, net	(2		)
Total increase in electric margin	$	147

Natural Gas Revenues and Margin

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

(Millions of Dollars)	2015			2014
Natural gas revenues	$	1,007		$	1,215
Cost of natural gas sold and transported	(502		)	(726		)
Natural gas margin	$	505		$	489

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)	2015 vs. 2014
Purchased natural gas adjustment clause recovery	$	(225	)
Estimated impact of weather	(6		)
DSM program revenues (offset by expenses)	(2		)
Non-fuel riders, partially offset by expenses	18
Gas transport - Cherokee pipeline	5
Retail rate increase (interim, subject to refund)	4
Other, net	(2		)
Total decrease in natural gas revenues	$	(208	)

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Natural Gas Margin

(Millions of Dollars)	2015 vs. 2014
Non-fuel riders, partially offset by expenses	$	18
Gas transport - Cherokee pipeline	5
Retail rate increase (interim, subject to refund)	4
Estimated impact of weather	(6		)
DSM program revenues (offset by expenses)	(2		)
Other, net	(3		)
Total increase in natural gas margin	$	16

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased by $10.1 million, or 1.3 percent, for 2015 compared with the same period in 2014.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2015 vs. 2014
Employee benefits	$	8
Electric and gas distribution costs	6
Other, net	(4		)
Total increase in O&M expenses	$	10

DSM Program Expenses— DSM program expenses decreased $11.1 million, or 7.9 percent, for 2015 compared with 2014.  The lower expense is primarily attributable to lower electric and gas recovery rates. Lower conservation and DSM program expenses are generally offset by lower revenues.

Depreciation and Amortization— Depreciation and amortization expense increased by approximately $32.5 million, or 8.6 percent, for 2015 compared with 2014.  The increase is primarily attributable to capital investments.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased by $33.4 million, or 20.6 percent, for 2015 compared with 2014. The increase is primarily due to higher property taxes.

AFUDC— AFUDC decreased by $44.0 million for 2015 compared with 2014.  The decrease was primarily due to implementation of the CACJA rider on Jan. 1, 2015, facilitating earlier and alternative recovery of construction costs.

Interest Charges —Interest charges increased by $5.5 million, or 3.2 percent, for 2015 compared with 2014.  The increase is primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased $34.8 million for 2015 compared with 2014.  The increase in income tax expense was primarily due to higher pretax earnings in 2015 and decreased permanent plant-related adjustments (e.g., AFUDC-equity) in 2015.  The ETR was 37.4 percent2015 compared with 34.9 percent for 2014 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.

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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.

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.

At Dec. 31, 2015, the fair values by source for net commodity trading contract assets were as follows:

	Futures / Forwards
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year	Maturity 1 to 3 Years		Maturity 4 to 5 Years	Maturity Greater Than 5 Years	Total Futures/ Forwards Fair Value
PSCo	1	128	(16	)	—	—	112

1 — Prices actively quoted or based on actively quoted prices.

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)	2015		2014
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	—	$	318
Contracts realized or settled during the period	14		(500		)
Commodity trading contract additions and changes during the period	98		182
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	112	$	—

At Dec. 31, 2015, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.1 million, whereas a 10 percent decrease would increase pretax income by approximately $0.1 million. At Dec. 31, 2014, there were no net commodity trading contract assets outstanding.

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
2015	$	0.10	$	3.00	$	0.28	$	1.34	$	0.06

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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, 2015, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately $0.1 million, and 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. 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, 2015, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $3.2 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $0.2 million.  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.

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, 2015.  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, 2015.

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, 2015.

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.

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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, 2015. 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, 2015, 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. 22, 2016	Feb. 22, 2016

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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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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 22, 2016

33

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2015			2014			2013
Operating revenues
Electric	$	3,115,257		$	3,125,937		$	3,081,171
Natural gas	1,006,666			1,215,324			1,080,703
Steam and other	41,590			41,888			40,754
Total operating revenues	4,163,513			4,383,149			4,202,628
Operating expenses
Electric fuel and purchased power	1,246,666			1,405,498			1,335,818
Cost of natural gas sold and transported	501,824			725,754			621,120
Cost of sales — steam and other	17,788			16,831			17,039
Operating and maintenance expenses	761,901			751,786			762,322
Demand side management program expenses	128,681			139,780			139,337
Depreciation and amortization	411,667			379,202			360,417
Taxes (other than income taxes)	195,285			161,928			137,816
Total operating expenses	3,263,812			3,580,779			3,373,869
Operating income	899,701			802,370			828,759
Other income, net	2,964			4,265			3,136
Allowance for funds used during construction —  equity	14,485			46,784			33,173
Interest charges and financing costs
Interest charges — includes other financing costs of $6,285, $6,340, and $6,866, respectively	177,430			171,881			173,602
Allowance for funds used during construction — debt	(5,522		)	(17,241		)	(12,657		)
Total interest charges and financing costs	171,908			154,640			160,945
Income before income taxes	745,242			698,779			704,123
Income taxes	278,440			243,591			250,740
Net income	$	466,802		$	455,188		$	453,383

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
	2015			2014			2013
Net income	$	466,802		$	455,188		$	453,383
Other comprehensive income (loss)
Derivative instruments:
Net fair value (decrease) increase, net of tax of $(20), $(43) and $5, respectively	(30		)	(72		)	9
Reclassification of losses (gains) to net income, net of tax of $39, $(287) and $(294), respectively	72			(468		)	(476		)
Other comprehensive income (loss)	42			(540		)	(467		)
Comprehensive income	$	466,844		$	454,648		$	452,916

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
	2015			2014			2013
Operating activities
Net income	$	466,802		$	455,188		$	453,383
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	416,427			383,992			365,713
Demand side management program amortization	3,509			4,331			4,802
Deferred income taxes	277,896			227,823			316,253
Amortization of investment tax credits	(2,807		)	(2,941		)	(2,935		)
Allowance for equity funds used during construction	(14,485		)	(46,784		)	(33,173		)
Provision for bad debts	13,052			17,005			16,784
Net realized and unrealized hedging and derivative transactions	2,414			(2,578		)	(3,571		)
Other	2,500			—			—
Changes in operating assets and liabilities:
Accounts receivable	8,872			(42,921		)	5,089
Accrued unbilled revenues	17,837			(23,132		)	14,707
Inventories	33,417			(972		)	(14,857		)
Prepayments and other	10,483			(81,715		)	(7,210		)
Accounts payable	(40,982		)	(22,789		)	59,361
Net regulatory assets and liabilities	78,055			130,499			108,400
Other current liabilities	19,654			5,284			16,561
Pension and other employee benefit obligations	(23,449		)	(38,905		)	(48,886		)
Change in other noncurrent assets	4,086			5,537			3,862
Change in other noncurrent liabilities	(35,334		)	(19,130		)	17,191
Net cash provided by operating activities	1,237,947			947,792			1,271,474
Investing activities
Utility capital/construction expenditures	(995,597		)	(1,114,338		)	(1,066,700		)
Allowance for equity funds used during construction	14,485			46,784			33,173
Investments in utility money pool arrangement	(196,300		)	(603,000		)	(1,495,000		)
Repayments from utility money pool arrangement	212,300			659,000			1,423,000
Net cash used in investing activities	(965,112		)	(1,011,554		)	(1,105,527		)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(368,000		)	382,000			(154,000		)
Borrowings under utility money pool arrangement	165,000			333,000			14,000
Repayments under utility money pool arrangement	(165,000		)	(333,000		)	(14,000		)
Proceeds from issuance of long-term debt	246,751			295,598			492,313
Repayments of long-term debt	—			(275,000		)	(250,000		)
Capital contributions from parent	175,210			81,498			25,621
Dividends paid to parent	(330,846		)	(433,788		)	(263,942		)
Net cash (used in) provided by financing activities	(276,885		)	50,308			(150,008		)
Net change in cash and cash equivalents	(4,050		)	(13,454		)	15,939
Cash and cash equivalents at beginning of period	7,635			21,089			5,150
Cash and cash equivalents at end of period	$	3,585		$	7,635		$	21,089
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(165,546	)	$	(150,011	)	$	(155,457	)
Cash received (paid) for income taxes, net	13,822			(91,810		)	34,946
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	106,912		$	139,616		$	142,103

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
	2015			2014
Assets
Current assets
Cash and cash equivalents	$	3,585		$	7,635
Accounts receivable, net	300,882			322,885
Accounts receivable from affiliates	4,909			50,842
Investments in utility money pool arrangement	—			16,000
Accrued unbilled revenues	276,212			294,049
Inventories	205,562			238,979
Regulatory assets	92,072			120,120
Deferred income taxes	62,662			64,587
Derivative instruments	1,945			1,731
Prepaid taxes	81,162			90,365
Prepayments and other	22,698			23,979
Total current assets	1,051,689			1,231,172
Property, plant and equipment, net	12,172,211			11,626,956
Other assets
Regulatory assets	906,275			903,973
Derivative instruments	3,478			5,176
Other	44,819			48,506
Total other assets	954,572			957,655
Total assets	$	14,178,472		$	13,815,783
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	8,103		$	8,178
Short-term debt	14,000			382,000
Accounts payable	352,701			425,133
Accounts payable to affiliates	76,643			46,736
Regulatory liabilities	152,823			134,459
Taxes accrued	166,660			159,470
Accrued interest	49,698			48,409
Dividends payable to parent	83,374			83,652
Derivative instruments	8,881			5,774
Other	78,910			72,002
Total current liabilities	991,793			1,365,813
Deferred credits and other liabilities
Deferred income taxes	2,720,860			2,437,641
Deferred investment tax credits	33,466			36,273
Regulatory liabilities	471,421			464,421
Asset retirement obligations	240,508			225,296
Derivative instruments	13,020			18,257
Customer advances	198,526			229,990
Pension and employee benefit obligations	200,774			202,031
Other	63,864			68,171
Total deferred credits and other liabilities	3,942,439			3,682,080
Commitments and contingencies
Capitalization
Long-term debt	4,124,088			3,882,051
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2015 and 2014, respectively	—			—
Additional paid in capital	3,620,824			3,522,788
Retained earnings	1,523,164			1,386,929
Accumulated other comprehensive loss	(23,836		)	(23,878		)
Total common stockholder’s equity	5,120,152			4,885,839
Total liabilities and equity	$	14,178,472		$	13,815,783

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, 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
Net income						466,802						466,802
Other comprehensive income									42			42
Common dividends declared to parent						(330,567		)				(330,567		)
Contribution of capital by parent				98,036								98,036
Balance at Dec. 31, 2015	100	$	—	$	3,620,824	$	1,523,164		$	(23,836	)	$	5,120,152

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
	2015			2014
Long-Term Debt
First Mortgage Bonds, Series due:
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
May 15, 2025, 2.9%	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			300,000
Capital lease obligations, through 2060, 11.2% — 14.3%	164,031			172,209
Unamortized discount	(11,340		)	(11,480		)
Total	4,132,191			3,890,229
Less current maturities	8,103			8,178
Total long-term debt	$	4,124,088		$	3,882,051
Common Stockholder’s Equity
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2015 and 2014, respectively.	$	—		$	—
Additional paid-in capital	3,620,824			3,522,788
Retained earnings	1,523,164			1,386,929
Accumulated other comprehensive loss	(23,836		)	(23,878		)
Total common stockholder’s equity	$	5,120,152		$	4,885,839

^(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 or OCI, 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 revenues 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.

Certain rate rider mechanisms qualify for alternative revenue recognition under generally accepted accounting principles. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety, or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.

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 20 unique DSM products, pilots and services for commercial and industrial customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures.

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 DSM program costs 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, 2.7 and 2.8 percent for the years ended Dec. 31, 2015, 2014 and 2013, 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.

41

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.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize only applies to federal ITCs. 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.

42

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.

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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.

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

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

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

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

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

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

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3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	321,004		$	346,007
Less allowance for bad debts	(20,122		)	(23,122		)
	$	300,882		$	322,885

(Thousands of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	58,128	$	55,491
Fuel	78,586		80,963
Natural gas	68,848		102,525
	$	205,562	$	238,979

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	11,856,126		$	10,927,867
Natural gas plant	3,420,249			3,210,242
Common and other property	862,840			827,708
Plant to be retired (a)	38,249			71,534
Construction work in progress	408,963			828,620
Total property, plant and equipment	16,586,427			15,865,971
Less accumulated depreciation	(4,414,216		)	(4,239,015		)
	$	12,172,211		$	11,626,956

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

4. 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, 2015
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	4
Maximum amount outstanding	34
Weighted average interest rate, computed on a daily basis	0.36		%
Weighted average interest rate at period end	N/A

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	1			4			—
Maximum amount outstanding	34			97			12
Weighted average interest rate, computed on a daily basis	0.41		%	0.25		%	0.36		%
Weighted average interest rate at period end	N/A			N/A			N/A

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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	14
Average amount outstanding	14
Maximum amount outstanding	68
Weighted average interest rate, computed on a daily basis	0.50		%
Weighted average interest rate at period end	0.60

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	14			382			—
Average amount outstanding	95			167			38
Maximum amount outstanding	449			393			332
Weighted average interest rate, computed on a daily basis	0.51		%	0.31		%	0.34		%
Weighted average interest rate at period end	0.60			0.65			N/A

Letters of Credit— PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2015 and 2014, there were $4 million and $6 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

Credit Agreement — PSCo has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $700 million and the credit facility matures in October 2019.

PSCo has the right to request an extension of the 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 45 percent and 47 percent at Dec. 31, 2015 and 2014, 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.

• PSCo was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2015 and 2014.

• 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.

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At Dec. 31, 2015, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700	$	18	$	682

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

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

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

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 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025. In 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044.

During the next five years, PSCo has long-term debt maturities of $130 million, $300 million, $400 million and $400 million due in 2017, 2018, 2019 and 2020, respectively.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $26.6 million and $26.5 million, net of amortization, at Dec. 31, 2015 and 2014, 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, 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, 2015:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	155,159	$	69,679	$	147	76	%
Hayden Unit 2	121,486		61,780		20,840		37
Hayden Common Facilities	37,756		17,910		321		53
Craig Units 1 and 2	60,158		36,570		8,518		10
Craig Common Facilities 1, 2 and 3	37,418		18,520		505		7
Comanche Unit 3	892,340		95,029		452		67
Comanche Common Facilities	23,826		1,430		894		82
Electric Transmission:
Transmission and other facilities, including substations	152,460		62,324		5,378		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	19,928		7,165		—		60
Gas Transportation Compressor	$	8,353	$	124	$	127	50
Total	$	1,508,884	$	370,531	$	37,182

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

Consolidated Appropriations Act, 2016- In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provides for the following:

• Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40 percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation;

• PTCs at 100 percent of the credit rate ($0.023 per KWh) for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;

• ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;

• R&E credit was permanently extended; and

• Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.

The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment.

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.

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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.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015.  PSCo is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals); however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2015, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits— The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	1.9
Unrecognized tax benefit — Temporary tax positions	15.0		10.0
Total unrecognized tax benefit	$	17.4	$	11.9

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

(Millions of Dollars)	2015			2014			2013
Balance at Jan. 1	$	11.9		$	8.4		$	9.6
Additions based on tax positions related to the current year	4.5			3.7			3.9
Reductions based on tax positions related to the current year	(1.5		)	(0.7		)	—
Additions for tax positions of prior years	2.5			2.8			3.3
Reductions for tax positions of prior years	—			(1.2		)	(0.9		)
Settlements with taxing authorities	—			(1.1		)	(7.5		)
Balance at Dec. 31	$	17.4		$	11.9		$	8.4

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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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(4.3	)	$	(3.9	)

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

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2015, 2014 and 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2015, 2014 or 2013.

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)	2015			2014
Federal NOL carryforward	$	328		$	320
Federal tax credit carryforwards	24			22
State NOL carryforwards	684			690
State tax credit carryforwards, net of federal detriment (a)	13			12
Valuation allowances for state credit carryforwards, net of federal detriment (b)	(1		)	—

^(a)  State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2015 and 2014, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million as of Dec. 31, 2015.

The federal carryforward periods expire between 2021 and 2035.  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:

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	3.2		2.8		3.0
Change in unrecognized tax benefits	0.1		(0.1	)	0.1
Regulatory differences — utility plant items	(0.3	)	(2.1	)	(1.4	)
Tax credits recognized, net of federal income tax expense	(0.7	)	(0.8	)	(0.8	)
Other, net	0.1		0.1		(0.3	)
Effective income tax rate	37.4	%	34.9	%	35.6	%

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

(Thousands of Dollars)	2015			2014			2013
Current federal tax (benefit) expense	$	(1,166	)	$	9,550		$	(52,408	)
Current state tax (benefit) expense	(727		)	2,611			(7,252		)
Current change in unrecognized tax expense (benefit)	5,244			6,548			(2,918		)
Deferred federal tax expense	246,096			208,781			273,916
Deferred state tax expense	36,450			26,196			38,243
Deferred change in unrecognized tax (benefit) expense	(4,650		)	(7,154		)	4,094
Deferred investment tax credits	(2,807		)	(2,941		)	(2,935		)
Total income tax expense	$	278,440		$	243,591		$	250,740

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

(Thousands of Dollars)	2015			2014			2013
Deferred tax expense excluding items below	$	285,144		$	254,142		$	335,580
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(7,229		)	(26,649		)	(19,616		)
Tax benefit allocated to other comprehensive income and other	(19		)	330			289
Deferred tax expense	$	277,896		$	227,823		$	316,253

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

(Thousands of Dollars)	2015		2014
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,772,043	$	2,467,260
Employee benefits	105,049		110,556
Other	101,219		140,080
Total deferred tax liabilities	$	2,978,311	$	2,717,896
Deferred tax assets:
NOL carryforward	$	147,763	$	143,158
Unbilled revenue - fuel costs	48,181		57,654
Rate refund	23,352		43,735
Tax credit carryforward	35,240		34,493
Regulatory liabilities	17,201		14,549
Deferred investment tax credits	12,718		13,781
Other	35,658		37,472
Total deferred tax assets	$	320,113	$	344,842
Net deferred tax liability	$	2,658,198	$	2,373,054

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, 2015, PSCo had 2,024 bargaining employees covered under a collective-bargaining agreement, which expires in May 2017.

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.

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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. Preferred stock is valued using recent trades and quoted prices of similar securities. 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, 2015 and 2014 were $41.8 million and $46.5 million, respectively, of which $3.6 million and $3.8 million were attributable to PSCo. In 2015 and 2014, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $9.5 million and $4.7 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 2015 were below the assumed level of 6.81 percent;

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

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

• In 2016, PSCo’s expected investment-return assumption is 6.84 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:

	2015		2014
Domestic and international equity securities	36	%	32	%
Long-duration fixed income and interest rate swap securities	32		35
Short-to-intermediate fixed income securities	12		12
Alternative investments	18		18
Cash	2		3
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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	81,954	$	—		$	—	$	81,954
Derivatives	—		1,204			—		1,204
Government securities	—		214,341			—		214,341
Corporate bonds	—		86,914			—		86,914
Asset-backed securities	—		881			—		881
Common stock	28,797		—			—		28,797
Private equity investments	—		—			34,353		34,353
Commingled funds	—		573,009			—		573,009
Real estate	—		—			18,681		18,681
Other	—		(3,453		)	—		(3,453		)
Total	$	110,751	$	872,896		$	53,034	$	1,036,681

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	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

The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2015, 2014 and 2013:

(Thousands of Dollars)	Jan. 1, 2015		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2015
Private equity investments	$	50,210	$	7,636	$	(20,036	)	$	(3,457	)	$	—	$	34,353
Real estate	18,410		1,925		(2,371		)	717			—		18,681
Total	$	68,620	$	9,561	$	(22,407	)	$	(2,740	)	$	—	$	53,034

(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.

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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)	2015			2014
Accumulated Benefit Obligation at Dec. 31	$	1,192,798		$	1,249,739
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,277,957		$	1,152,836
Service cost	28,260			23,939
Interest cost	50,857			53,277
Transfer to other plan	(2,938		)	(13,404		)
Actuarial (gain) loss	(54,737		)	133,215
Benefit payments	(74,749		)	(71,906		)
Obligation at Dec. 31	$	1,224,650		$	1,277,957

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,103,865		$	1,067,057
Actual (loss) return on plan assets	(9,122		)	84,871
Employer contributions	20,056			35,156
Transfer to other plan	(3,369		)	(11,313		)
Benefit payments	(74,749		)	(71,906		)
Fair value of plan assets at Dec. 31	$	1,036,681		$	1,103,865

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(187,969	)	$	(174,092	)

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

(Thousands of Dollars)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	521,703		$	530,674
Prior service credit	(15,572		)	(18,708		)
Total	$	506,131		$	511,966

(Thousands of Dollars)	2015		2014
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	$	28,852	$	31,774
Noncurrent regulatory assets	477,279		480,192
Total	$	506,131	$	511,966

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.66	%	4.11	%
Expected average long-term increase in compensation level	4.00		3.75
Mortality table	RP 2014		RP 2014

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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. During 2015, a new projection table was released (MP 2015). PSCo evaluated the updated projection table and concluded that the methodology adopted at Dec. 31, 2014 is consistent with the recently updated table and continues to be representative of its population.

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 2013 through 2016 to meet minimum funding requirements.

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

• $125.0 million in January 2016, of which $16.8 million was attributable to PSCo;

• $90.1 million in 2015, of which $20.1 million was attributable to PSCo;

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

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

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

Plan Amendments — In 2015 and 2014, 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)	2015			2014			2013
Service cost	$	28,260		$	23,939		$	25,206
Interest cost	50,857			53,277			46,160
Expected return on plan assets	(72,590		)	(70,709		)	(63,821		)
Amortization of prior service credit	(3,136		)	(3,092		)	(1,064		)
Amortization of net loss	36,377			33,892			43,418
Net periodic pension cost	39,768			37,307			49,899
Costs not recognized due to effects of regulation	(1,464		)	—			—
Net benefit cost recognized for financial reporting	$	38,304		$	37,307		$	49,899

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.11	%	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75		3.75
Expected average long-term rate of return on assets	6.81		6.81		6.47

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 $9.9 million, $9.4 million and $11.6 million in 2015, 2014 and 2013, 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 2016 pension cost calculations is 6.84 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.

57

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 $9.5 million in 2015, $9.1 million in 2014 and $8.7 million in 2013.

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 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.

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:

	2015		2014
Domestic and international equity securities	25	%	25	%
Short-to-intermediate fixed income securities	57		57
Alternative investments	13		13
Cash	5		5
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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	17,524	$	—		$	—	$	17,524
Government securities	—		35,016			—		35,016
Insurance contracts	—		42,123			—		42,123
Corporate bonds	—		65,031			—		65,031
Asset-backed securities	—		25,602			—		25,602
Mortgage-backed securities	—		31,778			—		31,778
Commingled funds	—		182,736			—		182,736
Other	—		(368		)	—		(368		)
Total	$	17,524	$	381,918		$	—	$	399,442

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	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

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

For the years ended Dec. 31, 2015 and 2014, there were no assets transferred in or out of Level 3. The following table presents the changes in PSCo’s Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2013:

(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.

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

(Thousands of Dollars)	2015			2014
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	443,753		$	508,971
Service cost	928			1,915
Interest cost	17,498			23,704
Medicare subsidy reimbursements	1,712			1,753
Plan participants’ contributions	4,961			4,625
Actuarial gain	(32,001		)	(63,130		)
Benefit payments	(33,277		)	(34,085		)
Obligation at Dec. 31	$	403,574		$	443,753

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	425,282		$	438,193
Actual (loss) return on plan assets	(3,076		)	11,060
Plan participants’ contributions	4,961			4,625
Employer contributions	5,552			5,489
Benefit payments	(33,277		)	(34,085		)
Fair value of plan assets at Dec. 31	$	399,442		$	425,282

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(Thousands of Dollars)	2015			2014
Funded Status at Dec. 31:
Funded status (a)	$	(4,132	)	$	(18,471	)

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

(Thousands of Dollars)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	49,226		$	56,823
Prior service credit	(33,942		)	(40,189		)
Total	$	15,284		$	16,634

(Thousands of Dollars)	2015		2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Noncurrent regulatory assets	$	15,284	$	16,634

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.65	%	4.08	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	6.00	%	6.50	%

Effective Jan. 1, 2016, the initial medical trend rate was decreased from 6.5 percent to 6.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is three 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	$	38,946	$	(33,136	)
Service and interest components	2,093		(1,743		)

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. Xcel Energy, which includes PSCo, contributed $18.3 million, $17.1 million and $17.6 million during 2015, 2014 and 2013, respectively, of which $5.6 million, $5.5 million and $7.0 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12.3 million during 2016, of which amounts attributable to PSCo will be zero.

Plan Amendments — In 2015 and 2014 there were no plan amendments made which affected the projected benefit obligation.

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	928		$	1,915		$	2,564
Interest cost	17,498			23,704			22,210
Expected return on plan assets	(23,803		)	(30,214		)	(29,227		)
Amortization of transition obligation	—			—			785
Amortization of prior service credit	(6,247		)	(6,247		)	(7,666		)
Amortization of net loss	2,475			6,434			13,699
Net periodic postretirement benefit (credit) cost	$	(9,149	)	$	(4,408	)	$	2,365

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.08	%	4.82	%	4.10	%
Expected average long-term rate of return on assets	5.80		7.18		7.11

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
2016	$	77,898	$	32,197	$	2,234	$	29,963
2017	77,952		32,356		2,373		29,983
2018	80,583		32,381		2,517		29,864
2019	82,760		32,402		2,647		29,755
2020	83,372		33,093		2,753		30,340
2021-2025	430,762		158,040		15,450		142,590

9. Other Income, Net

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

(Thousands of Dollars)	2015			2014			2013
Interest income	$	753		$	1,470		$	1,761
Other nonoperating income	2,408			3,601			2,603
Insurance policy expense	(197		)	(806		)	(1,228		)
Other income, net	$	2,964		$	4,265		$	3,136

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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, 2015, accumulated other comprehensive losses related to interest rate derivatives included $1.0 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for 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, 2015, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016.  PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in 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, 2015 and 2014.

At Dec. 31, 2015, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

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

(Amounts in Thousands)(a)(b)	2015	2014
MWh of electricity	684	—
MMBtu of natural gas	12,515	735
Gallons of vehicle fuel	63	127

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

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

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, 2015, three of PSCo’s 10 most significant counterparties for these activities, comprising $1.2 million or 2 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  Six of the 10 most significant counterparties, comprising $33.2 million or 48 percent of this credit exposure at Dec. 31, 2015, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.  Another of these significant counterparties, comprising $4.9 million or 7 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external and internal analysis. Nine of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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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)	2015			2014			2013
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,878	)	$	(23,338	)	$	(22,871	)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(30		)	(72		)	9
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	72			(468		)	(476		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23,836	)	$	(23,878	)	$	(23,338	)

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2015, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	54	(a)	$	—		$	—
Vehicle fuel and other commodity	(50		)	—			57		(b)	—			—
Total	$	(50	)	$	—		$	111		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	364		(c)
Natural gas commodity	—			(10,635		)	—			10,158		(e)	(7,620		)	(e)
Total	$	—		$	(10,635	)	$	—		$	10,158		$	(7,256	)

	Year Ended Dec. 31, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Gains 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	)

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	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 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	)

^(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, 2015 included $1.1 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, 2015, 2014 and 2013 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, 2015, 2014 and 2013.  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, 2015 and 2014, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of PSCo were downgraded below investment grade.

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

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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, 2015:

	Dec. 31, 2015
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	137	$	351	$	—	$	488	$	(324	)	$	164
Natural gas commodity	—		352		—		352		(286		)	66
Total current derivative assets	$	137	$	703	$	—	$	840	$	(610	)	230
PPAs (a)												1,715
Current derivative instruments												$	1,945
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	16	$	—	$	16	$	—		$	16
Total noncurrent derivative assets	$	—	$	16	$	—	$	16	$	—		16
PPAs (a)												3,462
Noncurrent derivative instruments												$	3,478
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	92	$	—	$	92	$	—		$	92
Other derivative instruments:
Commodity trading	34		325		—		359		(324		)	35
Natural gas commodity	—		3,850		—		3,850		(286		)	3,564
Total current derivative liabilities	$	34	$	4,267	$	—	$	4,301	$	(610	)	3,691
PPAs (a)												5,190
Current derivative instruments												$	8,881
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	33	$	—	$	33	$	—		$	33
Total noncurrent derivative liabilities	$	—	$	33	$	—	$	33	$	—		33
PPAs (a)												12,987
Noncurrent derivative instruments												$	13,020

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, PSCo qualified these contracts under the normal purchase exception.  Based 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, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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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, 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 on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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

There were no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2015, 2014 and 2013.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2015, 2014 and 2013.

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Fair Value of Long-Term Debt

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

	2015				2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,132,191	$	4,376,875	$	3,890,229	$	4,328,968

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2015 and 2014, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

11. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — CPUC

Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $66.2 million over three years. The request was based on a HTY ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the periods in the MYP and an equity ratio of 56 percent. In addition, PSCo requested an extension of its PSIA rider through 2020 to recover costs associated with its pipeline integrity efforts. The rider would recover incremental revenue of $42.8 million over three years.

In July 2015, PSCo filed rebuttal testimony with adjustments and modified recovery between base rates and the PSIA rider. The revised request is summarized below:

(Millions of Dollars)	2015			2016 Step			2017 Step
PSCo’s filed base rate request	$	40.5		$	7.6		$	18.1
Shift O&M expenses between PSIA and base rates	—			7.0			6.4
Rebuttal corrections and adjustments	—			—			(7.7		)
Total base rate increase	$	40.5		$	14.6		$	16.8
Incremental PSIA rider revenues	(0.1		)	14.7			21.7
Total revenue impact from rebuttal	$	40.4		$	29.3		$	38.5
Requested ROE	10.1		%	10.1		%	10.3		%
Rate base	$	1,260		$	1,310		$	1,360

In November 2015, the ALJ issued his recommended decision, which reflected a 2014 HTY with a 13-month average rate base, the Cherokee pipeline investment adjusted to year-end rate base, a ROE of 9.5 percent and an equity ratio of 56.51 percent. In addition, the ALJ’s recommendation included a three-year extension (2016 through 2018) of the PSIA rider with all O&M expenses transferred to base rates as well as certain other projects shifting between the PSIA rider and base rates, beginning January 2016.

The ALJ also recommended that certain expenses, including property taxes and damage prevention costs that exceed the 2014 HTY level, be deferred. He further recommended a pension cost tracker and certain other deferral related items.

In February 2016, the CPUC issued their written order. Key matters are as follows:

• 2014 HTY, with a 13-month average rate base, with the exception of the Cherokee pipeline which is included at a year-end level;

• Extension of the PSIA rider through 2018 with all O&M expenses transferred to base rates;

• A ROE of 9.5 percent; and

• An equity ratio of 56.51 percent.

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The following table reflects the ALJ’s position and the CPUC’s written order (estimated):

(Millions of Dollars)	ALJ			CPUC’s Written Order
PSCo’s filed 2015 base rate request (a)	$	40.5		$	40.5
ROE	(7.8		)	(7.8		)
Capital structure and cost of debt	(0.5		)	(0.5		)
Cherokee pipeline adjustment	4.1			4.1
Move to 2014 HTY	(14.1		)	(14.1		)
O&M expenses	(3.0		)	(2.4		)
Other, net	(1.1		)	(1.1		)
Overall recommended rate increase	$	18.1		$	18.7

^(a) The ALJ’s recommendation and the CPUC’s written order also includes approximately $20.0 million of PSIA costs be transferred to base rates, effective Jan. 1, 2016.

The ALJ’s recommendation, as well as the CPUC’s written order for the PSIA rider, are as follows (estimated):

	ALJ						CPUC’s Written Order
(Millions of Dollars)	2016			2017			2016			2017
PSCo’s filed incremental PSIA request	$	21.7		$	21.2		$	21.7		$	21.2
Transfer PSIA costs to base rates	(20.5		)	—			(20.5		)	—
PSIA cost recovery remaining in base	(4.3		)	—			(4.3		)	—
Projects not recovered through the PSIA	(3.6		)	(2.0		)	(3.3		)	(0.8		)
ROE and capital structure	(0.3		)	(1.6		)	(0.3		)	(1.6		)
Total	$	(7.0	)	$	17.6		$	(6.7	)	$	18.8

The following table summarizes the estimated annual pre-tax impact of the CPUC’s written order:

(Millions of Dollars)	2015			2016			2017
Base rate increase	$	18.7		$	19.7		$	—
Incremental PSIA rider revenues	(0.2		)	(6.7		)	18.8
Expense deferrals, net amortization (a)	(3.6		)	1.5			5.2
Estimated pre-tax impact	$	14.9		$	14.5		$	24.0

^(a) Deferral and amortization impacts relate primarily to recognition of accelerated amortization of prepaid pension assets and deferrals of pension expense in excess of the amount approved in the prior general gas rate case.

Interim rates, subject to refund, went into effect Oct. 1, 2015. PSCo has recognized management’s best estimate of the potential customer refund obligation.

Colorado 2015 Steam Rate Case — In November 2015, PSCo filed a request to increase Colorado retail steam rates by $3.5 million in 2016. In December 2015, the CPUC approved the filed request which recovers costs related to upgrades for the state steam plant as well as the Zuni Station and permits use of the Zuni Station exclusively for steam business. Final rates are implemented in two steps with $2.8 million, which began on Jan. 1, 2016, and the remaining $0.7 million which will be effective Nov. 1, 2016.

Annual Electric Earnings Test — In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test in which PSCo shares with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of Dec. 31, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test of $15 million. PSCo will file its 2015 earnings test with the CPUC in April 2016. The final sharing obligation will be based on the CPUC approved tariff and could vary from the current estimate.

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Electric, Purchased Gas and Resource Adjustment Clauses

DSM and the DSMCA — 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 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million. For the years 2016 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual spending limit of $84.3 million.

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

• A 2015 DSM electric budget of $81.6 million and a natural gas budget of $13.1 million; and

• A 2016 DSM electric budget of $78.7 million and a natural gas budget of $13.6 million.

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 liability balance approximately $5.5 million and $0.6 million in 2015 and 2014, respectively. The cumulative credit to the RESA regulatory liability balance was $110.6 million and $105.1 million at Dec. 31, 2015 and Dec. 31, 2014, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds. The current sharing mechanism, without modification, extends through 2017.

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 projects:

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 pipeline assessment and maintenance projects.

Electric Distribution Integrity Management Programs — PSCo is assessing aging infrastructure for distribution assets and replacing worn components to increase system performance.

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 2016 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, 2015, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2016	$	302.3	$	231.1	$	137.5
2017	230.3		129.5		137.2
2018	118.5		181.0		85.5
2019	42.0		187.6		51.0
2020	43.6		203.4		50.4
Thereafter	332.3		409.6		773.2
Total	$	1,069.0	$	1,342.2	$	1,234.8

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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, $69.5 million and $72.7 million in 2015, 2014 and 2013, respectively. At Dec. 31, 2015, 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)
2016	$	44.5	$	25.3
2017	24.3		4.4
2018	19.2		—
2019	10.3		—
2020	1.5		—
Thereafter	9.5		—
Total	$	109.3	$	29.7

^(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 $132.9 million and $138.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2015 and 2014, 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 $8.2 million, $7.2 million, and $6.3 million for 2015, 2014 and 2013, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(57.2		)	(49.0		)
Total property held under capital leases, net	$	164.0		$	172.2

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The remainder of the leases, primarily for 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 $130.5 million, $126.2 million and $96.6 million for 2015, 2014 and 2013, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $113.5 million, $110.1 million and $79.6 million in 2015, 2014 and 2013, 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
2016	$	12.0	$	102.2	$	114.2	$	29.3
2017	7.8		95.8		103.6		25.7
2018	7.4		96.0		103.4		25.3
2019	7.4		96.9		104.3		25.1
2020	7.4		97.7		105.1		24.9
Thereafter	39.5		579.7		619.2		486.5
Total minimum obligation							616.8
Interest component of obligation							(452.8		)
Present value of minimum obligation							$	164.0

^(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 of capacity under long-term PPAs as of Dec. 31, 2015, and 2014 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.

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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 wastes to that site.

MGP Sites— PSCo is currently involved in investigating and/or remediating several MGP sites where 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 2016. PSCo had accrued $1.7 million and $1.8 million for both of these sites at Dec. 31, 2015 and 2014, 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 September 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. PSCo estimates that the cost to comply with the new ELG rule will range from $9 million to $21 million, and could change as PSCo continues to assess alternate compliance technologies. PSCo believes that compliance costs would be recoverable through regulatory mechanisms.

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. PSCo does not anticipate the cost of compliance will have a material impact on the results of operations, financial position or cash flows.

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

Air

GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In October 2015, a final rule was published by the EPA for GHG emission standards for existing power plants.  States must develop implementation plans by September 2016, with the possibility of an extension to September 2018, or the EPA will prepare a federal plan for the state.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.  The CPP is currently being challenged by multiple parties in the D.C. Circuit Court.  In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule as well as ordered expedited review of the CPP, with briefings to be completed and oral arguments held by June 2016.  Following the D.C. Circuit Court’s denial of motions for stay, multiple parties filed requests for stay with the U.S. Supreme Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until, first, the D.C. Circuit Court and then the U.S. Supreme Court have ruled on the challenges to the CPP.

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PSCo has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals.  The CPP could require additional emission reductions in Colorado.  If state plans 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.  Until PSCo has more information about SIPs or knows the requirements of the EPA’s upcoming final rule on federal plans for the states that do not develop related plans, PSCo cannot predict the costs of compliance with the final rule once it takes effect.  PSCo believes compliance costs will be recoverable through regulatory mechanisms.  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 CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the 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 facilities included within the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Emission controls at Hayden Unit 1 were placed into service in November 2015 and Hayden Unit 2 is expected to be placed into service in late 2016, at an estimated combined cost of $75.2 million, completing the pollution control equipment required on PSCo plants under the CACJA. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

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

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant.  The Pawnee plant recently installed an SO₂ scrubber to reduce SO₂ emissions. The Colorado Department of Health and Environment made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA’s final decision is expected by summer 2016.  It is anticipated that the areas near PSCo’s other power plants would be evaluated in the next designation phase, ending December 2017. If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months, designed to achieve the NAAQS within five years. PSCo cannot evaluate the impacts of this ruling until the final designation of unclassified and nonattainment areas is made and any required state plan has been developed.

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

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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 and control panels. The asbestos recognition associated with electric production includes certain specific plants. The AROs recorded for PSCo steam and other production relate to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. 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.

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, 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.

In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. The estimated costs to comply with the final rule were incorporated into the cash flow revisions in 2015.

A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2015 and 2014 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2015		Accretion		Cash Flow     Revisions (a)			Ending Balance      Dec. 31, 2015 (b)
Electric plant
Steam and other production asbestos	$	36,856	$	1,820	$	—		$	38,676
Steam and other production ash containment	61,885		2,769		6,113			70,767
Wind production	2,095		18		(121		)	1,992
Electric distribution	1,182		47		(99		)	1,130
Other	1,150		46		(142		)	1,054
Natural gas plant
Gas transmission and distribution	117,474		4,694		—			122,168
Other	3,886		153		(114		)	3,925
Common and other property
Common miscellaneous	768		28		—			796
Total liability	$	225,296	$	9,575	$	5,637		$	240,508

^(a)  In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above.

^(b)  There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

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(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow    Revisions (a)			Ending Balance  Dec. 31, 2014 (b)
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)  In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas transmission and distribution.

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

Indeterminate AROs—PSCo has certain underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined. Additionally, outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2015. 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, 2015 and 2014 were $364 million and $366 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.

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Employment, Tort and Commercial Litigation

Pacific Northwest FERC Refund Proceeding — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In May 2015 in the remand proceeding, the FERC issued an order rejecting the City's claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In June 2015, the City requested the FERC grant rehearing of its order, which the FERC denied in December. The City may appeal this order.

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

Preliminary calculations of the City 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 scope of the proceeding established by FERC is being challenged in the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City 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.

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The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	29,260	$	497,973	$	32,195	$	500,889
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		144,953		—		141,214
Depreciation differences	1	One to sixteen years	14,221		99,835		10,700		104,743
Net AROs (b)	1, 12	Plant lives	—		62,948		—		46,213
Purchased power contract costs	12	Term of related contract	1,319		29,143		858		29,596
Property tax		One to six years	21,558		14,428		28,024		31,429
Contract valuation adjustments (c)	10	Term of related contract	9,376		9,526		8,901		12,999
Losses on reacquired debt	4	Term of related debt	1,421		6,957		1,426		8,378
Conservation programs (d)	1, 11	One to five years	8,466		6,947		10,198		10,906
Gas pipeline inspection costs	12	Less than one year	3,611		—		5,416		3,611
Recoverable purchased natural gas and electric energy costs	1	Less than one year	408		—		18,410		—
Other		Various	2,432		33,565		3,992		13,995
Total regulatory assets			$	92,072	$	906,275	$	120,120	$	903,973

^(a)  Includes $4.4 million and $4.5 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2015 and 2014, respectively.

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

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

^(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, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	364,291	$	—	$	366,359
Renewable resources and environmental initiatives	11, 12	Various	3,311		40,988		3,308		10,376
Investment tax credit deferrals	1, 7	Various	—		20,515		—		22,225
Deferred income tax adjustment	1	Various	—		16,891		—		18,672
PSCo earnings test	11	One to two years	42,868		9,472		57,127		42,819
Gas pipeline inspection costs	12	One to two years	1,140		4,273		13,970		642
Deferred electric, gas and steam production costs	1	Less than one year	66,696		—		24,035		—
Conservation programs (a)	1, 11	Less than one year	33,460		—		32,226		—
Low income discount program		Less than one year	1,393		—		1,680		—
Gain from asset sales		One to three years	—		—		316		4
Other		Various	3,955		14,991		1,797		3,324
Total regulatory liabilities (b)			$	152,823	$	471,421	$	134,459	$	464,421

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

^(b)  Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current liabilities.

At Dec. 31, 2015 and 2014, approximately $54 million and $104 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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14. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2015			Year Ended Dec. 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)	$	(23,338	)
Other comprehensive loss before reclassifications	(30		)	(72		)
Losses (gains) reclassified from net accumulated other comprehensive loss	72			(468		)
Net current period other comprehensive income (loss)	42			(540		)
Accumulated other comprehensive loss at Dec. 31	$	(23,836	)	$	(23,878	)

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2015				Year Ended Dec. 31, 2014
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	54		(a)	$	(730	)	(a)
Vehicle fuel derivatives	57			(b)	(25		)	(b)
Total, pre-tax	111				(755		)
Tax expense	(39		)		287
Total amounts reclassified, net of tax	$	72			$	(468	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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 wholesale commodity and 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.

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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
2015
Operating revenues (a)	$	3,115,257	$	1,006,666	$	41,590		$	—		$	4,163,513
Intersegment revenues	301		67		—			(368		)	—
Total revenues	$	3,115,558	$	1,006,733	$	41,590		$	(368	)	$	4,163,513
Depreciation and amortization	$	311,122	$	96,384	$	4,161		$	—		$	411,667
Interest charges and financing costs	136,397		34,935		576			—			171,908
Income tax expense (benefit)	234,873		44,192		(625		)	—			278,440
Net Income	391,257		74,267		1,278			—			466,802

(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

^(a)  Operating revenues include $13 million, $14 million and $13 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013, 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.

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

(Thousands of Dollars)	2015		2014		2013
Operating revenues:
Electric	$	8,632	$	9,614	$	8,136
Other	4,441		4,441		4,441
Operating expenses:
Purchased power	—		23		1,331
Other operating expenses — paid to Xcel Energy Services Inc.	414,620		454,250		375,766
Interest expense	211		158		132
Interest income	45		61		273

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

	2015				2014
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	4,419	$	—	$	—	$	6,706
NSP-Wisconsin	71		—		22		—
SPS	414		—		5,803		—
Other subsidiaries of Xcel Energy Inc.	5		76,643		45,017		40,030
	$	4,909	$	76,643	$	50,842	$	46,736

17. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2015		June 30, 2015		Sept. 30, 2015		Dec. 31, 2015
Operating revenues	$	1,135,450	$	952,521	$	1,044,704	$	1,030,838
Operating income	215,400		195,176		315,174		173,951
Net income	110,966		98,500		173,081		84,255

	Quarter Ended
(Thousands of Dollars)	March 31, 2014		June 30, 2014		Sept. 30, 2014		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

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, 2015, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

81

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, 2015 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.

Effective January 2016, PSCo implemented the general ledger modules of a new enterprise resource planning (“ERP”) system to improve certain financial and related transaction processes. During 2016 and 2017, PSCo will continue implementing additional modules and expects to begin conversion of existing work management system to this same ERP system. In connection with this ongoing implementation, PSCo is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting procedures. PSCo does not believe that this implementation will have an adverse effect on its internal control over financial reporting.

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

Information required under this Item is contained in Xcel Energy Inc.'s Proxy Statement for its 2016 Annual Meeting of Shareholders, which is incorporated by reference.

Item 14 — Principal Accountant Fees and Services

The information required by Item 14 of From 10-K is set forth under the heading "Independent Registered Public Accounting Firm - Audit and Non-Audit Fees" in Xcel energy Inc.'s definitive Proxy Statement for the 2016 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2016. Such information set forth under such heading is incorporated herein by this reference hereto.

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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, 2015.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2015, 2014, and 2013.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2015, 2014, and 2013.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2015, 2014, and 2013.
	Consolidated Balance Sheets — As of Dec. 31, 2015 and 2014.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2015, 2014 and 2013.
	Consolidated Statements of Capitalization — As of Dec. 31, 2015 and 2014.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2015, 2014, and 2013.
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).

83

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)).
4.13*	Supplemental Indenture dated as of May 1, 2015 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250,000,000 principal amount of 2.90 percent First Mortgage Bonds, Series No. 28 due 2025. (Exhibit 4.01 to Form 8-K of PSCo dated May 12, 2015 (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).

84

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).
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-K 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-K 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)).
10.29*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2015).
10.30*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. (As First Effective May 20, 2015) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.02 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034).
10.31*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions (Restricted Stock Units and Performance Share Units) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.03 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034).
10.32*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan Form of Award Agreement. (Exhibit 10.28 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015).
10.33*+	Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.29 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015).

85

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, 2015 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) 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, 2015, 2014 AND 2013

(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:
2015	$	23,122	$	13,052	$	5,175	$	21,227	$	20,122
2014	22,505		17,005		6,240		22,628		23,122
2013	21,918		16,784		7,005		23,202		22,505

^(a)  Recovery of amounts previously written off.

^(b)  Deductions relate primarily to bad debt write-offs.

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. 22, 2016	/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
	2015		2014		2013		2012		2011
Earnings, as defined:
Pretax income	$	745,242	$	698,779	$	704,123	$	690,620	$	625,164
Add: Fixed charges	235,530		232,832		232,539		254,443		253,867
Total earnings, as defined	$	980,772	$	931,611	$	936,662	$	945,063	$	879,031
Fixed charges, as defined:
Interest charges	$	177,430	$	171,881	$	173,602	$	188,094	$	186,885
Interest charges on life insurance policy borrowings	233		214		245		310		332
Interest component of leases	57,867		60,737		58,692		66,039		66,650
Total fixed charges, as defined	$	235,530	$	232,832	$	232,539	$	254,443	$	253,867
Ratio of earnings to fixed charges	4.2		4.0		4.0		3.7		3.5

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-203664-04 on Form S-3 of our report dated February 22, 2016, 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, 2015.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2016

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. 22, 2016

/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. 22, 2016

/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, 2015, 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. 22, 2016

/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, 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

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	PUBLIC SERVICE CO OF COLORADO
Entity Central Index Key	0000081018
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Document Type	10-K
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Entity Common Stock, Shares Outstanding		100

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues
Electric	$ 3,115,257	$ 3,125,937	$ 3,081,171
Natural gas	1,006,666	1,215,324	1,080,703
Steam and other	41,590	41,888	40,754
Total operating revenues	4,163,513	4,383,149	4,202,628
Operating expenses
Electric fuel and purchased power	1,246,666	1,405,498	1,335,818
Cost of natural gas sold and transported	501,824	725,754	621,120
Cost of sales — steam and other	17,788	16,831	17,039
Operating and maintenance expenses	761,901	751,786	762,322
Demand side management program expenses	128,681	139,780	139,337
Depreciation and amortization	411,667	379,202	360,417
Taxes (other than income taxes)	195,285	161,928	137,816
Total operating expenses	3,263,812	3,580,779	3,373,869
Operating income	899,701	802,370	828,759
Other income, net	2,964	4,265	3,136
Allowance for funds used during construction — equity	14,485	46,784	33,173
Interest charges and financing costs
Interest charges — includes other financing costs of $6,285, $6,340, and $6,866, respectively	177,430	171,881	173,602
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(5,522)	(17,241)	(12,657)
Total interest charges and financing costs	171,908	154,640	160,945
Income before income taxes	745,242	698,779	704,123
Income taxes	278,440	243,591	250,740
Net income	$ 466,802	$ 455,188	$ 453,383

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest charges and financing costs
Other financing costs	$ 6,285	$ 6,340	$ 6,866

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Comprehensive income:
Net income	$ 466,802	$ 455,188	$ 453,383
Derivative instruments:
Net fair value (decrease) increase, net of tax of $(20), $(43) and $5, respectively	(30)	(72)	9
Reclassification of losses (gains) to net income, net of tax of $39, $(287) and $(294), respectively	72	(468)	(476)
Other comprehensive income (loss)	42	(540)	(467)
Comprehensive income	$ 466,844	$ 454,648	$ 452,916

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative instruments:
Net fair value (decrease) increase, tax	$ (20)	$ 5	$ (5,708)
Reclassification of losses (gains) to net income, tax	$ 39	$ (294)	$ (725)

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities
Net income	$ 466,802	$ 455,188	$ 453,383
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	416,427	383,992	365,713
Demand side management program amortization	3,509	4,331	4,802
Deferred income taxes	277,896	227,823	316,253
Amortization of Investment Tax Credits	(2,807)	(2,941)	(2,935)
Allowance for equity funds used during construction	(14,485)	(46,784)	(33,173)
Provision for bad debts	13,052	17,005	16,784
Net realized and unrealized hedging and derivative transactions	2,414	(2,578)	(3,571)
Other Operating Activities, Cash Flow Statement	2,500	0	0
Changes in operating assets and liabilities:
Accounts receivable	8,872	(42,921)	5,089
Accrued unbilled revenues	17,837	(23,132)	14,707
Inventories	33,417	(972)	(14,857)
Prepayments and other	10,483	(81,715)	(7,210)
Accounts payable	(40,982)	(22,789)	59,361
Net regulatory assets and liabilities	78,055	130,499	108,400
Other current liabilities	19,654	5,284	16,561
Pension and other employee benefit obligations	(23,449)	(38,905)	(48,886)
Change in other noncurrent assets	4,086	5,537	3,862
Change in other noncurrent liabilities	(35,334)	(19,130)	17,191
Net cash provided by (used in) operating activities	1,237,947	947,792	1,271,474
Investing activities
Utility capital/construction expenditures	(995,597)	(1,114,338)	(1,066,700)
Allowance for equity funds used during construction	14,485	46,784	33,173
Investments in utility money pool arrangement	(196,300)	(603,000)	(1,495,000)
Repayments from utility money pool arrangement	212,300	659,000	1,423,000
Net cash provided by (used in) investing activities	(965,112)	(1,011,554)	(1,105,527)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	(368,000)	382,000	(154,000)
Borrowings under utility money pool arrangement	165,000	333,000	14,000
Repayments under utility money pool arrangement	(165,000)	(333,000)	(14,000)
Proceeds from issuance of long-term debt	246,751	295,598	492,313
Repayments of long-term debt	0	(275,000)	(250,000)
Capital contributions from parent	175,210	81,498	25,621
Dividends paid to parent	(330,846)	(433,788)	(263,942)
Net cash provided by (used in) financing activities	(276,885)	50,308	(150,008)
Net change in cash and cash equivalents	(4,050)	(13,454)	15,939
Cash and cash equivalents at beginning of period	7,635	21,089	5,150
Cash and cash equivalents at end of period	3,585	7,635	21,089
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(165,546)	(150,011)	(155,457)
Cash received (paid) for income taxes, net	13,822	(91,810)	34,946
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 106,912	$ 139,616	$ 142,103

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents		$ 3,585	$ 7,635
Accounts receivable, net		300,882	322,885
Accounts receivable from affiliates		4,909	50,842
Investments in utility money pool arrangement		0	16,000
Accrued unbilled revenues		276,212	294,049
Inventories		205,562	238,979
Regulatory assets		92,072	120,120
Deferred income taxes		62,662	64,587
Derivative instruments		1,945	1,731
Prepaid Taxes		81,162	90,365
Prepayments and other		22,698	23,979
Total current assets		1,051,689	1,231,172
Property, plant and equipment, net		12,172,211	11,626,956
Other assets
Regulatory assets		906,275	903,973
Derivative instruments		3,478	5,176
Other		44,819	48,506
Total other assets		954,572	957,655
Total assets		14,178,472	13,815,783
Current liabilities
Current portion of long-term debt		8,103	8,178
Short-term debt		14,000	382,000
Accounts payable		352,701	425,133
Accounts payable to affiliates		76,643	46,736
Regulatory liabilities	[1]	152,823	134,459
Taxes accrued		166,660	159,470
Accrued interest		49,698	48,409
Dividends payable to parent		83,374	83,652
Derivative instruments		8,881	5,774
Other		78,910	72,002
Total current liabilities		991,793	1,365,813
Deferred credits and other liabilities
Deferred income taxes		2,720,860	2,437,641
Deferred investment tax credits		33,466	36,273
Regulatory liabilities		471,421	464,421
Asset retirement obligations		240,508	225,296
Derivative instruments		13,020	18,257
Customer advances		198,526	229,990
Pension and employee benefit obligations		200,774	202,031
Other		63,864	68,171
Total deferred credits and other liabilities		$ 3,942,439	$ 3,682,080
Commitments and contingencies
Capitalization
Long-term debt		$ 4,124,088	$ 3,882,051
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2015 and 2014, respectively		0	0
Additional paid in capital		3,620,824	3,522,788
Retained earnings		1,523,164	1,386,929
Accumulated other comprehensive loss		(23,836)	(23,878)
Total common stockholder’s equity		5,120,152	4,885,839
Total liabilities and equity		$ 14,178,472	$ 13,815,783

[1] Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current liabilities.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
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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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Beginning 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
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
Increase (Decrease) in Stockholder's Equity
Net income	$ 466,802			466,802
Other comprehensive income (loss)	42				42
Common dividends declared to parent	(330,567)			(330,567)
Contribution of capital by parent	98,036		98,036
Ending Balance at Dec. 31, 2015	$ 5,120,152	$ 0	$ 3,620,824	$ 1,523,164	$ (23,836)
Balance (in shares) at Dec. 31, 2015	100	100

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CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		$ (11,340)	$ (11,480)
Total long-term debt		4,132,191	3,890,229
Less current maturities		8,103	8,178
Long-term Debt and Capital Lease Obligations		4,124,088	3,882,051
Common Stockholder's Equity
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2015 and 2014, respectively.		0	0
Additional paid in capital		3,620,824	3,522,788
Retained earnings		1,523,164	1,386,929
Accumulated other comprehensive loss		(23,836)	(23,878)
Total common stockholder’s equity		5,120,152	4,885,839
First Mortgage Bonds | Series Due Sept. 1, 2017
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	[1]	129,500	129,500
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 May 15, 2025 [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		250,000	0
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	300,000
Capital Lease Obligations
Schedule of Capitalization, Long-term Debt [Line Items]
Capital lease obligations		$ 164,031	$ 172,209

[1] Pollution control financing.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Common Stockholder's Equity
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
First Mortgage Bonds | Series Due Sept. 1, 2017
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	4.375%	4.375%
Debt instrument, maturity date	Sep. 01, 2017	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%	5.80%
Debt instrument, maturity date	Aug. 01, 2018	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%	5.125%
Debt instrument, maturity date	Jun. 01, 2019	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%	3.20%
Debt instrument, maturity date	Nov. 15, 2020	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%	2.25%
Debt instrument, maturity date	Sep. 15, 2022	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%	2.50%
Debt instrument, maturity date	Mar. 15, 2023	Mar. 15, 2023
First Mortgage Bonds | Series Due May 15, 2025 [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	2.90%
Debt instrument, maturity date	May 15, 2025
First Mortgage Bonds | Series Due Sept. 1, 2037
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	6.25%	6.25%
Debt instrument, maturity date	Sep. 01, 2037	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%	6.50%
Debt instrument, maturity date	Aug. 01, 2038	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%	4.75%
Debt instrument, maturity date	Aug. 15, 2041	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%	3.60%
Debt instrument, maturity date	Sep. 15, 2042	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%	3.95%
Debt instrument, maturity date	Mar. 15, 2043	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%	4.30%
Debt instrument, maturity date	Mar. 15, 2044	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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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

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 or OCI, 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 revenues 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.

Certain rate rider mechanisms qualify for alternative revenue recognition under generally accepted accounting principles. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety, or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.

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 20 unique DSM products, pilots and services for commercial and industrial customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures.

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 DSM program costs 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, 2.7 and 2.8 percent for the years ended Dec. 31, 2015, 2014 and 2013, 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.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize only applies to federal ITCs. 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.

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 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, 2015 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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Accounting Pronouncements

12 Months Ended

Dec. 31, 2015

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

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

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

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

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

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

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Selected Balance Sheet Data

12 Months Ended

Dec. 31, 2015

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	321,004		$	346,007
Less allowance for bad debts	(20,122		)	(23,122		)
	$	300,882		$	322,885

(Thousands of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	58,128	$	55,491
Fuel	78,586		80,963
Natural gas	68,848		102,525
	$	205,562	$	238,979

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	11,856,126		$	10,927,867
Natural gas plant	3,420,249			3,210,242
Common and other property	862,840			827,708
Plant to be retired (a)	38,249			71,534
Construction work in progress	408,963			828,620
Total property, plant and equipment	16,586,427			15,865,971
Less accumulated depreciation	(4,414,216		)	(4,239,015		)
	$	12,172,211		$	11,626,956

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

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Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2015
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	4
Maximum amount outstanding	34
Weighted average interest rate, computed on a daily basis	0.36		%
Weighted average interest rate at period end	N/A

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	1			4			—
Maximum amount outstanding	34			97			12
Weighted average interest rate, computed on a daily basis	0.41		%	0.25		%	0.36		%
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	14
Average amount outstanding	14
Maximum amount outstanding	68
Weighted average interest rate, computed on a daily basis	0.50		%
Weighted average interest rate at period end	0.60

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	14			382			—
Average amount outstanding	95			167			38
Maximum amount outstanding	449			393			332
Weighted average interest rate, computed on a daily basis	0.51		%	0.31		%	0.34		%
Weighted average interest rate at period end	0.60			0.65			N/A

Letters of Credit— PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2015 and 2014, there were $4 million and $6 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

Credit Agreement — PSCo has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $700 million and the credit facility matures in October 2019.

PSCo has the right to request an extension of the 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 45 percent and 47 percent at Dec. 31, 2015 and 2014, 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.

• PSCo was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2015 and 2014.

• 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, 2015, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700	$	18	$	682

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

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

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

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 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025. In 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044.

During the next five years, PSCo has long-term debt maturities of $130 million, $300 million, $400 million and $400 million due in 2017, 2018, 2019 and 2020, respectively.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $26.6 million and $26.5 million, net of amortization, at Dec. 31, 2015 and 2014, 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, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

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Preferred Stock

12 Months Ended

Dec. 31, 2015

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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Joint Ownership of Generation, Transmission and Gas Facilities Joint Ownership of Generation, Transmission and Gas Facilities

12 Months Ended

Dec. 31, 2015

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, 2015:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	155,159	$	69,679	$	147	76	%
Hayden Unit 2	121,486		61,780		20,840		37
Hayden Common Facilities	37,756		17,910		321		53
Craig Units 1 and 2	60,158		36,570		8,518		10
Craig Common Facilities 1, 2 and 3	37,418		18,520		505		7
Comanche Unit 3	892,340		95,029		452		67
Comanche Common Facilities	23,826		1,430		894		82
Electric Transmission:
Transmission and other facilities, including substations	152,460		62,324		5,378		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	19,928		7,165		—		60
Gas Transportation Compressor	$	8,353	$	124	$	127	50
Total	$	1,508,884	$	370,531	$	37,182

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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Income Taxes Income Taxes

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Consolidated Appropriations Act, 2016- In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provides for the following:

• Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40 percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation;

• PTCs at 100 percent of the credit rate ($0.023 per KWh) for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;

• ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;

• R&E credit was permanently extended; and

• Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.

The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment.

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.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015.  PSCo is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals); however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2015, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits— The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	1.9
Unrecognized tax benefit — Temporary tax positions	15.0		10.0
Total unrecognized tax benefit	$	17.4	$	11.9

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

(Millions of Dollars)	2015			2014			2013
Balance at Jan. 1	$	11.9		$	8.4		$	9.6
Additions based on tax positions related to the current year	4.5			3.7			3.9
Reductions based on tax positions related to the current year	(1.5		)	(0.7		)	—
Additions for tax positions of prior years	2.5			2.8			3.3
Reductions for tax positions of prior years	—			(1.2		)	(0.9		)
Settlements with taxing authorities	—			(1.1		)	(7.5		)
Balance at Dec. 31	$	17.4		$	11.9		$	8.4

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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(4.3	)	$	(3.9	)

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

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2015, 2014 and 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2015, 2014 or 2013.

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)	2015			2014
Federal NOL carryforward	$	328		$	320
Federal tax credit carryforwards	24			22
State NOL carryforwards	684			690
State tax credit carryforwards, net of federal detriment (a)	13			12
Valuation allowances for state credit carryforwards, net of federal detriment (b)	(1		)	—

^(a)  State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2015 and 2014, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million as of Dec. 31, 2015.

The federal carryforward periods expire between 2021 and 2035.  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:

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	3.2		2.8		3.0
Change in unrecognized tax benefits	0.1		(0.1	)	0.1
Regulatory differences — utility plant items	(0.3	)	(2.1	)	(1.4	)
Tax credits recognized, net of federal income tax expense	(0.7	)	(0.8	)	(0.8	)
Other, net	0.1		0.1		(0.3	)
Effective income tax rate	37.4	%	34.9	%	35.6	%

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

(Thousands of Dollars)	2015			2014			2013
Current federal tax (benefit) expense	$	(1,166	)	$	9,550		$	(52,408	)
Current state tax (benefit) expense	(727		)	2,611			(7,252		)
Current change in unrecognized tax expense (benefit)	5,244			6,548			(2,918		)
Deferred federal tax expense	246,096			208,781			273,916
Deferred state tax expense	36,450			26,196			38,243
Deferred change in unrecognized tax (benefit) expense	(4,650		)	(7,154		)	4,094
Deferred investment tax credits	(2,807		)	(2,941		)	(2,935		)
Total income tax expense	$	278,440		$	243,591		$	250,740

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

(Thousands of Dollars)	2015			2014			2013
Deferred tax expense excluding items below	$	285,144		$	254,142		$	335,580
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(7,229		)	(26,649		)	(19,616		)
Tax benefit allocated to other comprehensive income and other	(19		)	330			289
Deferred tax expense	$	277,896		$	227,823		$	316,253

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

(Thousands of Dollars)	2015		2014
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,772,043	$	2,467,260
Employee benefits	105,049		110,556
Other	101,219		140,080
Total deferred tax liabilities	$	2,978,311	$	2,717,896
Deferred tax assets:
NOL carryforward	$	147,763	$	143,158
Unbilled revenue - fuel costs	48,181		57,654
Rate refund	23,352		43,735
Tax credit carryforward	35,240		34,493
Regulatory liabilities	17,201		14,549
Deferred investment tax credits	12,718		13,781
Other	35,658		37,472
Total deferred tax assets	$	320,113	$	344,842
Net deferred tax liability	$	2,658,198	$	2,373,054

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Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2015

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, 2015, PSCo had 2,024 bargaining employees covered under a collective-bargaining agreement, which expires in May 2017.

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. Preferred stock is valued using recent trades and quoted prices of similar securities. 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, 2015 and 2014 were $41.8 million and $46.5 million, respectively, of which $3.6 million and $3.8 million were attributable to PSCo. In 2015 and 2014, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $9.5 million and $4.7 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 2015 were below the assumed level of 6.81 percent;

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

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

• In 2016, PSCo’s expected investment-return assumption is 6.84 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:

	2015		2014
Domestic and international equity securities	36	%	32	%
Long-duration fixed income and interest rate swap securities	32		35
Short-to-intermediate fixed income securities	12		12
Alternative investments	18		18
Cash	2		3
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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	81,954	$	—		$	—	$	81,954
Derivatives	—		1,204			—		1,204
Government securities	—		214,341			—		214,341
Corporate bonds	—		86,914			—		86,914
Asset-backed securities	—		881			—		881
Common stock	28,797		—			—		28,797
Private equity investments	—		—			34,353		34,353
Commingled funds	—		573,009			—		573,009
Real estate	—		—			18,681		18,681
Other	—		(3,453		)	—		(3,453		)
Total	$	110,751	$	872,896		$	53,034	$	1,036,681

	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

The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2015, 2014 and 2013:

(Thousands of Dollars)	Jan. 1, 2015		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2015
Private equity investments	$	50,210	$	7,636	$	(20,036	)	$	(3,457	)	$	—	$	34,353
Real estate	18,410		1,925		(2,371		)	717			—		18,681
Total	$	68,620	$	9,561	$	(22,407	)	$	(2,740	)	$	—	$	53,034

(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.

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)	2015			2014
Accumulated Benefit Obligation at Dec. 31	$	1,192,798		$	1,249,739
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,277,957		$	1,152,836
Service cost	28,260			23,939
Interest cost	50,857			53,277
Transfer to other plan	(2,938		)	(13,404		)
Actuarial (gain) loss	(54,737		)	133,215
Benefit payments	(74,749		)	(71,906		)
Obligation at Dec. 31	$	1,224,650		$	1,277,957

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,103,865		$	1,067,057
Actual (loss) return on plan assets	(9,122		)	84,871
Employer contributions	20,056			35,156
Transfer to other plan	(3,369		)	(11,313		)
Benefit payments	(74,749		)	(71,906		)
Fair value of plan assets at Dec. 31	$	1,036,681		$	1,103,865

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(187,969	)	$	(174,092	)

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

(Thousands of Dollars)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	521,703		$	530,674
Prior service credit	(15,572		)	(18,708		)
Total	$	506,131		$	511,966

(Thousands of Dollars)	2015		2014
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	$	28,852	$	31,774
Noncurrent regulatory assets	477,279		480,192
Total	$	506,131	$	511,966

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.66	%	4.11	%
Expected average long-term increase in compensation level	4.00		3.75
Mortality table	RP 2014		RP 2014

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. During 2015, a new projection table was released (MP 2015). PSCo evaluated the updated projection table and concluded that the methodology adopted at Dec. 31, 2014 is consistent with the recently updated table and continues to be representative of its population.

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 2013 through 2016 to meet minimum funding requirements.

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

• $125.0 million in January 2016, of which $16.8 million was attributable to PSCo;

• $90.1 million in 2015, of which $20.1 million was attributable to PSCo;

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

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

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

Plan Amendments — In 2015 and 2014, 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)	2015			2014			2013
Service cost	$	28,260		$	23,939		$	25,206
Interest cost	50,857			53,277			46,160
Expected return on plan assets	(72,590		)	(70,709		)	(63,821		)
Amortization of prior service credit	(3,136		)	(3,092		)	(1,064		)
Amortization of net loss	36,377			33,892			43,418
Net periodic pension cost	39,768			37,307			49,899
Costs not recognized due to effects of regulation	(1,464		)	—			—
Net benefit cost recognized for financial reporting	$	38,304		$	37,307		$	49,899

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.11	%	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75		3.75
Expected average long-term rate of return on assets	6.81		6.81		6.47

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 $9.9 million, $9.4 million and $11.6 million in 2015, 2014 and 2013, 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 2016 pension cost calculations is 6.84 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 $9.5 million in 2015, $9.1 million in 2014 and $8.7 million in 2013.

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 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.

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:

	2015		2014
Domestic and international equity securities	25	%	25	%
Short-to-intermediate fixed income securities	57		57
Alternative investments	13		13
Cash	5		5
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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	17,524	$	—		$	—	$	17,524
Government securities	—		35,016			—		35,016
Insurance contracts	—		42,123			—		42,123
Corporate bonds	—		65,031			—		65,031
Asset-backed securities	—		25,602			—		25,602
Mortgage-backed securities	—		31,778			—		31,778
Commingled funds	—		182,736			—		182,736
Other	—		(368		)	—		(368		)
Total	$	17,524	$	381,918		$	—	$	399,442

	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

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

For the years ended Dec. 31, 2015 and 2014, there were no assets transferred in or out of Level 3. The following table presents the changes in PSCo’s Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2013:

(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.

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

(Thousands of Dollars)	2015			2014
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	443,753		$	508,971
Service cost	928			1,915
Interest cost	17,498			23,704
Medicare subsidy reimbursements	1,712			1,753
Plan participants’ contributions	4,961			4,625
Actuarial gain	(32,001		)	(63,130		)
Benefit payments	(33,277		)	(34,085		)
Obligation at Dec. 31	$	403,574		$	443,753

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	425,282		$	438,193
Actual (loss) return on plan assets	(3,076		)	11,060
Plan participants’ contributions	4,961			4,625
Employer contributions	5,552			5,489
Benefit payments	(33,277		)	(34,085		)
Fair value of plan assets at Dec. 31	$	399,442		$	425,282

(Thousands of Dollars)	2015			2014
Funded Status at Dec. 31:
Funded status (a)	$	(4,132	)	$	(18,471	)

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

(Thousands of Dollars)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	49,226		$	56,823
Prior service credit	(33,942		)	(40,189		)
Total	$	15,284		$	16,634

(Thousands of Dollars)	2015		2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Noncurrent regulatory assets	$	15,284	$	16,634

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.65	%	4.08	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	6.00	%	6.50	%

Effective Jan. 1, 2016, the initial medical trend rate was decreased from 6.5 percent to 6.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is three 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	$	38,946	$	(33,136	)
Service and interest components	2,093		(1,743		)

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. Xcel Energy, which includes PSCo, contributed $18.3 million, $17.1 million and $17.6 million during 2015, 2014 and 2013, respectively, of which $5.6 million, $5.5 million and $7.0 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12.3 million during 2016, of which amounts attributable to PSCo will be zero.

Plan Amendments — In 2015 and 2014 there were no plan amendments made which affected the projected benefit obligation.

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	928		$	1,915		$	2,564
Interest cost	17,498			23,704			22,210
Expected return on plan assets	(23,803		)	(30,214		)	(29,227		)
Amortization of transition obligation	—			—			785
Amortization of prior service credit	(6,247		)	(6,247		)	(7,666		)
Amortization of net loss	2,475			6,434			13,699
Net periodic postretirement benefit (credit) cost	$	(9,149	)	$	(4,408	)	$	2,365

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.08	%	4.82	%	4.10	%
Expected average long-term rate of return on assets	5.80		7.18		7.11

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
2016	$	77,898	$	32,197	$	2,234	$	29,963
2017	77,952		32,356		2,373		29,983
2018	80,583		32,381		2,517		29,864
2019	82,760		32,402		2,647		29,755
2020	83,372		33,093		2,753		30,340
2021-2025	430,762		158,040		15,450		142,590

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Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

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, 2015, accumulated other comprehensive losses related to interest rate derivatives included $1.0 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for 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, 2015, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016.  PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in 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, 2015 and 2014.

At Dec. 31, 2015, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

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

(Amounts in Thousands)(a)(b)	2015	2014
MWh of electricity	684	—
MMBtu of natural gas	12,515	735
Gallons of vehicle fuel	63	127

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

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

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, 2015, three of PSCo’s 10 most significant counterparties for these activities, comprising $1.2 million or 2 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  Six of the 10 most significant counterparties, comprising $33.2 million or 48 percent of this credit exposure at Dec. 31, 2015, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.  Another of these significant counterparties, comprising $4.9 million or 7 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external and internal analysis. Nine 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)	2015			2014			2013
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,878	)	$	(23,338	)	$	(22,871	)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(30		)	(72		)	9
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	72			(468		)	(476		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23,836	)	$	(23,878	)	$	(23,338	)

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2015, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	54	(a)	$	—		$	—
Vehicle fuel and other commodity	(50		)	—			57		(b)	—			—
Total	$	(50	)	$	—		$	111		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	364		(c)
Natural gas commodity	—			(10,635		)	—			10,158		(e)	(7,620		)	(e)
Total	$	—		$	(10,635	)	$	—		$	10,158		$	(7,256	)

	Year Ended Dec. 31, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Gains 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 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	)

^(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, 2015 included $1.1 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, 2015, 2014 and 2013 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, 2015, 2014 and 2013.  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, 2015 and 2014, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of PSCo were downgraded below investment grade.

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

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, 2015:

	Dec. 31, 2015
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	137	$	351	$	—	$	488	$	(324	)	$	164
Natural gas commodity	—		352		—		352		(286		)	66
Total current derivative assets	$	137	$	703	$	—	$	840	$	(610	)	230
PPAs (a)												1,715
Current derivative instruments												$	1,945
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	16	$	—	$	16	$	—		$	16
Total noncurrent derivative assets	$	—	$	16	$	—	$	16	$	—		16
PPAs (a)												3,462
Noncurrent derivative instruments												$	3,478
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	92	$	—	$	92	$	—		$	92
Other derivative instruments:
Commodity trading	34		325		—		359		(324		)	35
Natural gas commodity	—		3,850		—		3,850		(286		)	3,564
Total current derivative liabilities	$	34	$	4,267	$	—	$	4,301	$	(610	)	3,691
PPAs (a)												5,190
Current derivative instruments												$	8,881
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	33	$	—	$	33	$	—		$	33
Total noncurrent derivative liabilities	$	—	$	33	$	—	$	33	$	—		33
PPAs (a)												12,987
Noncurrent derivative instruments												$	13,020

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, PSCo qualified these contracts under the normal purchase exception.  Based 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, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents, for each of the fair value hierarchy levels, PSCo’s 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 on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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

There were no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2015, 2014 and 2013.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2015, 2014 and 2013.

Fair Value of Long-Term Debt

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

	2015				2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,132,191	$	4,376,875	$	3,890,229	$	4,328,968

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2015 and 2014, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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Other Income, Net

12 Months Ended

Dec. 31, 2015

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)	2015			2014			2013
Interest income	$	753		$	1,470		$	1,761
Other nonoperating income	2,408			3,601			2,603
Insurance policy expense	(197		)	(806		)	(1,228		)
Other income, net	$	2,964		$	4,265		$	3,136

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Rate Matters

12 Months Ended

Dec. 31, 2015

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Pending and Recently Concluded Regulatory Proceedings — CPUC

Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $66.2 million over three years. The request was based on a HTY ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the periods in the MYP and an equity ratio of 56 percent. In addition, PSCo requested an extension of its PSIA rider through 2020 to recover costs associated with its pipeline integrity efforts. The rider would recover incremental revenue of $42.8 million over three years.

In July 2015, PSCo filed rebuttal testimony with adjustments and modified recovery between base rates and the PSIA rider. The revised request is summarized below:

(Millions of Dollars)	2015			2016 Step			2017 Step
PSCo’s filed base rate request	$	40.5		$	7.6		$	18.1
Shift O&M expenses between PSIA and base rates	—			7.0			6.4
Rebuttal corrections and adjustments	—			—			(7.7		)
Total base rate increase	$	40.5		$	14.6		$	16.8
Incremental PSIA rider revenues	(0.1		)	14.7			21.7
Total revenue impact from rebuttal	$	40.4		$	29.3		$	38.5
Requested ROE	10.1		%	10.1		%	10.3		%
Rate base	$	1,260		$	1,310		$	1,360

In November 2015, the ALJ issued his recommended decision, which reflected a 2014 HTY with a 13-month average rate base, the Cherokee pipeline investment adjusted to year-end rate base, a ROE of 9.5 percent and an equity ratio of 56.51 percent. In addition, the ALJ’s recommendation included a three-year extension (2016 through 2018) of the PSIA rider with all O&M expenses transferred to base rates as well as certain other projects shifting between the PSIA rider and base rates, beginning January 2016.

The ALJ also recommended that certain expenses, including property taxes and damage prevention costs that exceed the 2014 HTY level, be deferred. He further recommended a pension cost tracker and certain other deferral related items.

In February 2016, the CPUC issued their written order. Key matters are as follows:

• 2014 HTY, with a 13-month average rate base, with the exception of the Cherokee pipeline which is included at a year-end level;

• Extension of the PSIA rider through 2018 with all O&M expenses transferred to base rates;

• A ROE of 9.5 percent; and

• An equity ratio of 56.51 percent.

The following table reflects the ALJ’s position and the CPUC’s written order (estimated):

(Millions of Dollars)	ALJ			CPUC’s Written Order
PSCo’s filed 2015 base rate request (a)	$	40.5		$	40.5
ROE	(7.8		)	(7.8		)
Capital structure and cost of debt	(0.5		)	(0.5		)
Cherokee pipeline adjustment	4.1			4.1
Move to 2014 HTY	(14.1		)	(14.1		)
O&M expenses	(3.0		)	(2.4		)
Other, net	(1.1		)	(1.1		)
Overall recommended rate increase	$	18.1		$	18.7

^(a) The ALJ’s recommendation and the CPUC’s written order also includes approximately $20.0 million of PSIA costs be transferred to base rates, effective Jan. 1, 2016.

The ALJ’s recommendation, as well as the CPUC’s written order for the PSIA rider, are as follows (estimated):

	ALJ						CPUC’s Written Order
(Millions of Dollars)	2016			2017			2016			2017
PSCo’s filed incremental PSIA request	$	21.7		$	21.2		$	21.7		$	21.2
Transfer PSIA costs to base rates	(20.5		)	—			(20.5		)	—
PSIA cost recovery remaining in base	(4.3		)	—			(4.3		)	—
Projects not recovered through the PSIA	(3.6		)	(2.0		)	(3.3		)	(0.8		)
ROE and capital structure	(0.3		)	(1.6		)	(0.3		)	(1.6		)
Total	$	(7.0	)	$	17.6		$	(6.7	)	$	18.8

The following table summarizes the estimated annual pre-tax impact of the CPUC’s written order:

(Millions of Dollars)	2015			2016			2017
Base rate increase	$	18.7		$	19.7		$	—
Incremental PSIA rider revenues	(0.2		)	(6.7		)	18.8
Expense deferrals, net amortization (a)	(3.6		)	1.5			5.2
Estimated pre-tax impact	$	14.9		$	14.5		$	24.0

^(a) Deferral and amortization impacts relate primarily to recognition of accelerated amortization of prepaid pension assets and deferrals of pension expense in excess of the amount approved in the prior general gas rate case.

Interim rates, subject to refund, went into effect Oct. 1, 2015. PSCo has recognized management’s best estimate of the potential customer refund obligation.

Colorado 2015 Steam Rate Case — In November 2015, PSCo filed a request to increase Colorado retail steam rates by $3.5 million in 2016. In December 2015, the CPUC approved the filed request which recovers costs related to upgrades for the state steam plant as well as the Zuni Station and permits use of the Zuni Station exclusively for steam business. Final rates are implemented in two steps with $2.8 million, which began on Jan. 1, 2016, and the remaining $0.7 million which will be effective Nov. 1, 2016.

Annual Electric Earnings Test — In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test in which PSCo shares with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of Dec. 31, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test of $15 million. PSCo will file its 2015 earnings test with the CPUC in April 2016. The final sharing obligation will be based on the CPUC approved tariff and could vary from the current estimate.

Electric, Purchased Gas and Resource Adjustment Clauses

DSM and the DSMCA — 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 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million. For the years 2016 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual spending limit of $84.3 million.

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

• A 2015 DSM electric budget of $81.6 million and a natural gas budget of $13.1 million; and

• A 2016 DSM electric budget of $78.7 million and a natural gas budget of $13.6 million.

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 liability balance approximately $5.5 million and $0.6 million in 2015 and 2014, respectively. The cumulative credit to the RESA regulatory liability balance was $110.6 million and $105.1 million at Dec. 31, 2015 and Dec. 31, 2014, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds. The current sharing mechanism, without modification, extends through 2017.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

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 projects:

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 pipeline assessment and maintenance projects.

Electric Distribution Integrity Management Programs — PSCo is assessing aging infrastructure for distribution assets and replacing worn components to increase system performance.

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 2016 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, 2015, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2016	$	302.3	$	231.1	$	137.5
2017	230.3		129.5		137.2
2018	118.5		181.0		85.5
2019	42.0		187.6		51.0
2020	43.6		203.4		50.4
Thereafter	332.3		409.6		773.2
Total	$	1,069.0	$	1,342.2	$	1,234.8

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, $69.5 million and $72.7 million in 2015, 2014 and 2013, respectively. At Dec. 31, 2015, 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)
2016	$	44.5	$	25.3
2017	24.3		4.4
2018	19.2		—
2019	10.3		—
2020	1.5		—
Thereafter	9.5		—
Total	$	109.3	$	29.7

^(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 $132.9 million and $138.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2015 and 2014, 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 $8.2 million, $7.2 million, and $6.3 million for 2015, 2014 and 2013, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(57.2		)	(49.0		)
Total property held under capital leases, net	$	164.0		$	172.2

The remainder of the leases, primarily for 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 $130.5 million, $126.2 million and $96.6 million for 2015, 2014 and 2013, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $113.5 million, $110.1 million and $79.6 million in 2015, 2014 and 2013, 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
2016	$	12.0	$	102.2	$	114.2	$	29.3
2017	7.8		95.8		103.6		25.7
2018	7.4		96.0		103.4		25.3
2019	7.4		96.9		104.3		25.1
2020	7.4		97.7		105.1		24.9
Thereafter	39.5		579.7		619.2		486.5
Total minimum obligation							616.8
Interest component of obligation							(452.8		)
Present value of minimum obligation							$	164.0

^(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 of capacity under long-term PPAs as of Dec. 31, 2015, and 2014 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 wastes to that site.

MGP Sites— PSCo is currently involved in investigating and/or remediating several MGP sites where 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 2016. PSCo had accrued $1.7 million and $1.8 million for both of these sites at Dec. 31, 2015 and 2014, 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 September 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. PSCo estimates that the cost to comply with the new ELG rule will range from $9 million to $21 million, and could change as PSCo continues to assess alternate compliance technologies. PSCo believes that compliance costs would be recoverable through regulatory mechanisms.

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. PSCo does not anticipate the cost of compliance will have a material impact on the results of operations, financial position or cash flows.

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

Air

GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In October 2015, a final rule was published by the EPA for GHG emission standards for existing power plants.  States must develop implementation plans by September 2016, with the possibility of an extension to September 2018, or the EPA will prepare a federal plan for the state.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.  The CPP is currently being challenged by multiple parties in the D.C. Circuit Court.  In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule as well as ordered expedited review of the CPP, with briefings to be completed and oral arguments held by June 2016.  Following the D.C. Circuit Court’s denial of motions for stay, multiple parties filed requests for stay with the U.S. Supreme Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until, first, the D.C. Circuit Court and then the U.S. Supreme Court have ruled on the challenges to the CPP.

PSCo has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals.  The CPP could require additional emission reductions in Colorado.  If state plans 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.  Until PSCo has more information about SIPs or knows the requirements of the EPA’s upcoming final rule on federal plans for the states that do not develop related plans, PSCo cannot predict the costs of compliance with the final rule once it takes effect.  PSCo believes compliance costs will be recoverable through regulatory mechanisms.  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 CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the 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 facilities included within the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Emission controls at Hayden Unit 1 were placed into service in November 2015 and Hayden Unit 2 is expected to be placed into service in late 2016, at an estimated combined cost of $75.2 million, completing the pollution control equipment required on PSCo plants under the CACJA. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

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

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant.  The Pawnee plant recently installed an SO₂ scrubber to reduce SO₂ emissions. The Colorado Department of Health and Environment made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA’s final decision is expected by summer 2016.  It is anticipated that the areas near PSCo’s other power plants would be evaluated in the next designation phase, ending December 2017. If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months, designed to achieve the NAAQS within five years. PSCo cannot evaluate the impacts of this ruling until the final designation of unclassified and nonattainment areas is made and any required state plan has been developed.

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

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 and control panels. The asbestos recognition associated with electric production includes certain specific plants. The AROs recorded for PSCo steam and other production relate to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. 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.

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, 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.

In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. The estimated costs to comply with the final rule were incorporated into the cash flow revisions in 2015.

A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2015 and 2014 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2015		Accretion		Cash Flow     Revisions (a)			Ending Balance      Dec. 31, 2015 (b)
Electric plant
Steam and other production asbestos	$	36,856	$	1,820	$	—		$	38,676
Steam and other production ash containment	61,885		2,769		6,113			70,767
Wind production	2,095		18		(121		)	1,992
Electric distribution	1,182		47		(99		)	1,130
Other	1,150		46		(142		)	1,054
Natural gas plant
Gas transmission and distribution	117,474		4,694		—			122,168
Other	3,886		153		(114		)	3,925
Common and other property
Common miscellaneous	768		28		—			796
Total liability	$	225,296	$	9,575	$	5,637		$	240,508

^(a)  In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above.

^(b)  There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow    Revisions (a)			Ending Balance  Dec. 31, 2014 (b)
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)  In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas transmission and distribution.

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

Indeterminate AROs—PSCo has certain underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined. Additionally, outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2015. 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, 2015 and 2014 were $364 million and $366 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 — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In May 2015 in the remand proceeding, the FERC issued an order rejecting the City's claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In June 2015, the City requested the FERC grant rehearing of its order, which the FERC denied in December. The City may appeal this order.

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

Preliminary calculations of the City 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 scope of the proceeding established by FERC is being challenged in the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City 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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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2015

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, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	29,260	$	497,973	$	32,195	$	500,889
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		144,953		—		141,214
Depreciation differences	1	One to sixteen years	14,221		99,835		10,700		104,743
Net AROs (b)	1, 12	Plant lives	—		62,948		—		46,213
Purchased power contract costs	12	Term of related contract	1,319		29,143		858		29,596
Property tax		One to six years	21,558		14,428		28,024		31,429
Contract valuation adjustments (c)	10	Term of related contract	9,376		9,526		8,901		12,999
Losses on reacquired debt	4	Term of related debt	1,421		6,957		1,426		8,378
Conservation programs (d)	1, 11	One to five years	8,466		6,947		10,198		10,906
Gas pipeline inspection costs	12	Less than one year	3,611		—		5,416		3,611
Recoverable purchased natural gas and electric energy costs	1	Less than one year	408		—		18,410		—
Other		Various	2,432		33,565		3,992		13,995
Total regulatory assets			$	92,072	$	906,275	$	120,120	$	903,973

^(a)  Includes $4.4 million and $4.5 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2015 and 2014, respectively.

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

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

^(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, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	364,291	$	—	$	366,359
Renewable resources and environmental initiatives	11, 12	Various	3,311		40,988		3,308		10,376
Investment tax credit deferrals	1, 7	Various	—		20,515		—		22,225
Deferred income tax adjustment	1	Various	—		16,891		—		18,672
PSCo earnings test	11	One to two years	42,868		9,472		57,127		42,819
Gas pipeline inspection costs	12	One to two years	1,140		4,273		13,970		642
Deferred electric, gas and steam production costs	1	Less than one year	66,696		—		24,035		—
Conservation programs (a)	1, 11	Less than one year	33,460		—		32,226		—
Low income discount program		Less than one year	1,393		—		1,680		—
Gain from asset sales		One to three years	—		—		316		4
Other		Various	3,955		14,991		1,797		3,324
Total regulatory liabilities (b)			$	152,823	$	471,421	$	134,459	$	464,421

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

^(b)  Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current liabilities.

At Dec. 31, 2015 and 2014, approximately $54 million and $104 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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Other Comprehensive Income

12 Months Ended

Dec. 31, 2015

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, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2015			Year Ended Dec. 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)	$	(23,338	)
Other comprehensive loss before reclassifications	(30		)	(72		)
Losses (gains) reclassified from net accumulated other comprehensive loss	72			(468		)
Net current period other comprehensive income (loss)	42			(540		)
Accumulated other comprehensive loss at Dec. 31	$	(23,836	)	$	(23,878	)

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2015				Year Ended Dec. 31, 2014
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	54		(a)	$	(730	)	(a)
Vehicle fuel derivatives	57			(b)	(25		)	(b)
Total, pre-tax	111				(755		)
Tax expense	(39		)		287
Total amounts reclassified, net of tax	$	72			$	(468	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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Segments and Related Information

12 Months Ended

Dec. 31, 2015

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 wholesale commodity and 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
2015
Operating revenues (a)	$	3,115,257	$	1,006,666	$	41,590		$	—		$	4,163,513
Intersegment revenues	301		67		—			(368		)	—
Total revenues	$	3,115,558	$	1,006,733	$	41,590		$	(368	)	$	4,163,513
Depreciation and amortization	$	311,122	$	96,384	$	4,161		$	—		$	411,667
Interest charges and financing costs	136,397		34,935		576			—			171,908
Income tax expense (benefit)	234,873		44,192		(625		)	—			278,440
Net Income	391,257		74,267		1,278			—			466,802

(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

^(a)  Operating revenues include $13 million, $14 million and $13 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013, respectively. See Note 16 for further discussion of related party transactions by reportable segment.

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Related Party Transactions

12 Months Ended

Dec. 31, 2015

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)	2015		2014		2013
Operating revenues:
Electric	$	8,632	$	9,614	$	8,136
Other	4,441		4,441		4,441
Operating expenses:
Purchased power	—		23		1,331
Other operating expenses — paid to Xcel Energy Services Inc.	414,620		454,250		375,766
Interest expense	211		158		132
Interest income	45		61		273

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

	2015				2014
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	4,419	$	—	$	—	$	6,706
NSP-Wisconsin	71		—		22		—
SPS	414		—		5,803		—
Other subsidiaries of Xcel Energy Inc.	5		76,643		45,017		40,030
	$	4,909	$	76,643	$	50,842	$	46,736

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2015		June 30, 2015		Sept. 30, 2015		Dec. 31, 2015
Operating revenues	$	1,135,450	$	952,521	$	1,044,704	$	1,030,838
Operating income	215,400		195,176		315,174		173,951
Net income	110,966		98,500		173,081		84,255

	Quarter Ended
(Thousands of Dollars)	March 31, 2014		June 30, 2014		Sept. 30, 2014		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

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Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2015

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, 2015, 2014 AND 2013

(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:
2015	$	23,122	$	13,052	$	5,175	$	21,227	$	20,122
2014	22,505		17,005		6,240		22,628		23,122
2013	21,918		16,784		7,005		23,202		22,505

^(a)  Recovery of amounts previously written off.

^(b)  Deductions relate primarily to bad debt write-offs.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

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 or OCI, 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 revenues 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 20 unique DSM products, pilots and services for commercial and industrial customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures.

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 DSM program costs 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, 2.7 and 2.8 percent for the years ended Dec. 31, 2015, 2014 and 2013, 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.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize only applies to federal ITCs. 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.

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 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, 2015 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, 2015

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	321,004		$	346,007
Less allowance for bad debts	(20,122		)	(23,122		)
	$	300,882		$	322,885

Inventories

(Thousands of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	58,128	$	55,491
Fuel	78,586		80,963
Natural gas	68,848		102,525
	$	205,562	$	238,979

Property, Plant and Equipment, Net

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	11,856,126		$	10,927,867
Natural gas plant	3,420,249			3,210,242
Common and other property	862,840			827,708
Plant to be retired (a)	38,249			71,534
Construction work in progress	408,963			828,620
Total property, plant and equipment	16,586,427			15,865,971
Less accumulated depreciation	(4,414,216		)	(4,239,015		)
	$	12,172,211		$	11,626,956

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

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Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At Dec. 31, 2015, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700	$	18	$	682

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

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

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money Pool — 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, 2015
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	4
Maximum amount outstanding	34
Weighted average interest rate, computed on a daily basis	0.36		%
Weighted average interest rate at period end	N/A

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	1			4			—
Maximum amount outstanding	34			97			12
Weighted average interest rate, computed on a daily basis	0.41		%	0.25		%	0.36		%
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	14
Average amount outstanding	14
Maximum amount outstanding	68
Weighted average interest rate, computed on a daily basis	0.50		%
Weighted average interest rate at period end	0.60

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	14			382			—
Average amount outstanding	95			167			38
Maximum amount outstanding	449			393			332
Weighted average interest rate, computed on a daily basis	0.51		%	0.31		%	0.34		%
Weighted average interest rate at period end	0.60			0.65			N/A

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2015

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

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Joint Ownership of Generation, Transmission and Gas Facilities (Tables)

12 Months Ended

Dec. 31, 2015

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, 2015:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	155,159	$	69,679	$	147	76	%
Hayden Unit 2	121,486		61,780		20,840		37
Hayden Common Facilities	37,756		17,910		321		53
Craig Units 1 and 2	60,158		36,570		8,518		10
Craig Common Facilities 1, 2 and 3	37,418		18,520		505		7
Comanche Unit 3	892,340		95,029		452		67
Comanche Common Facilities	23,826		1,430		894		82
Electric Transmission:
Transmission and other facilities, including substations	152,460		62,324		5,378		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	19,928		7,165		—		60
Gas Transportation Compressor	$	8,353	$	124	$	127	50
Total	$	1,508,884	$	370,531	$	37,182

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	1.9
Unrecognized tax benefit — Temporary tax positions	15.0		10.0
Total unrecognized tax benefit	$	17.4	$	11.9

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

(Millions of Dollars)	2015			2014			2013
Balance at Jan. 1	$	11.9		$	8.4		$	9.6
Additions based on tax positions related to the current year	4.5			3.7			3.9
Reductions based on tax positions related to the current year	(1.5		)	(0.7		)	—
Additions for tax positions of prior years	2.5			2.8			3.3
Reductions for tax positions of prior years	—			(1.2		)	(0.9		)
Settlements with taxing authorities	—			(1.1		)	(7.5		)
Balance at Dec. 31	$	17.4		$	11.9		$	8.4

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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(4.3	)	$	(3.9	)

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)	2015			2014
Federal NOL carryforward	$	328		$	320
Federal tax credit carryforwards	24			22
State NOL carryforwards	684			690
State tax credit carryforwards, net of federal detriment (a)	13			12
Valuation allowances for state credit carryforwards, net of federal detriment (b)	(1		)	—

^(a)  State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2015 and 2014, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million as of Dec. 31, 2015.

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:

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	3.2		2.8		3.0
Change in unrecognized tax benefits	0.1		(0.1	)	0.1
Regulatory differences — utility plant items	(0.3	)	(2.1	)	(1.4	)
Tax credits recognized, net of federal income tax expense	(0.7	)	(0.8	)	(0.8	)
Other, net	0.1		0.1		(0.3	)
Effective income tax rate	37.4	%	34.9	%	35.6	%

Schedule of Components of Income Tax Expense (Benefit)

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

(Thousands of Dollars)	2015			2014			2013
Current federal tax (benefit) expense	$	(1,166	)	$	9,550		$	(52,408	)
Current state tax (benefit) expense	(727		)	2,611			(7,252		)
Current change in unrecognized tax expense (benefit)	5,244			6,548			(2,918		)
Deferred federal tax expense	246,096			208,781			273,916
Deferred state tax expense	36,450			26,196			38,243
Deferred change in unrecognized tax (benefit) expense	(4,650		)	(7,154		)	4,094
Deferred investment tax credits	(2,807		)	(2,941		)	(2,935		)
Total income tax expense	$	278,440		$	243,591		$	250,740

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

(Thousands of Dollars)	2015			2014			2013
Deferred tax expense excluding items below	$	285,144		$	254,142		$	335,580
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(7,229		)	(26,649		)	(19,616		)
Tax benefit allocated to other comprehensive income and other	(19		)	330			289
Deferred tax expense	$	277,896		$	227,823		$	316,253

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)	2015		2014
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,772,043	$	2,467,260
Employee benefits	105,049		110,556
Other	101,219		140,080
Total deferred tax liabilities	$	2,978,311	$	2,717,896
Deferred tax assets:
NOL carryforward	$	147,763	$	143,158
Unbilled revenue - fuel costs	48,181		57,654
Rate refund	23,352		43,735
Tax credit carryforward	35,240		34,493
Regulatory liabilities	17,201		14,549
Deferred investment tax credits	12,718		13,781
Other	35,658		37,472
Total deferred tax assets	$	320,113	$	344,842
Net deferred tax liability	$	2,658,198	$	2,373,054

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Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2015

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
2016	$	77,898	$	32,197	$	2,234	$	29,963
2017	77,952		32,356		2,373		29,983
2018	80,583		32,381		2,517		29,864
2019	82,760		32,402		2,647		29,755
2020	83,372		33,093		2,753		30,340
2021-2025	430,762		158,040		15,450		142,590

Pension Plans

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	81,954	$	—		$	—	$	81,954
Derivatives	—		1,204			—		1,204
Government securities	—		214,341			—		214,341
Corporate bonds	—		86,914			—		86,914
Asset-backed securities	—		881			—		881
Common stock	28,797		—			—		28,797
Private equity investments	—		—			34,353		34,353
Commingled funds	—		573,009			—		573,009
Real estate	—		—			18,681		18,681
Other	—		(3,453		)	—		(3,453		)
Total	$	110,751	$	872,896		$	53,034	$	1,036,681

	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

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

	2015		2014
Domestic and international equity securities	36	%	32	%
Long-duration fixed income and interest rate swap securities	32		35
Short-to-intermediate fixed income securities	12		12
Alternative investments	18		18
Cash	2		3
Total	100	%	100	%

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, 2015, 2014 and 2013:

(Thousands of Dollars)	Jan. 1, 2015		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2015
Private equity investments	$	50,210	$	7,636	$	(20,036	)	$	(3,457	)	$	—	$	34,353
Real estate	18,410		1,925		(2,371		)	717			—		18,681
Total	$	68,620	$	9,561	$	(22,407	)	$	(2,740	)	$	—	$	53,034

(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.

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)	2015			2014
Accumulated Benefit Obligation at Dec. 31	$	1,192,798		$	1,249,739
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,277,957		$	1,152,836
Service cost	28,260			23,939
Interest cost	50,857			53,277
Transfer to other plan	(2,938		)	(13,404		)
Actuarial (gain) loss	(54,737		)	133,215
Benefit payments	(74,749		)	(71,906		)
Obligation at Dec. 31	$	1,224,650		$	1,277,957

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,103,865		$	1,067,057
Actual (loss) return on plan assets	(9,122		)	84,871
Employer contributions	20,056			35,156
Transfer to other plan	(3,369		)	(11,313		)
Benefit payments	(74,749		)	(71,906		)
Fair value of plan assets at Dec. 31	$	1,036,681		$	1,103,865

Funded Status of Plans

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(187,969	)	$	(174,092	)

^(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)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	521,703		$	530,674
Prior service credit	(15,572		)	(18,708		)
Total	$	506,131		$	511,966

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)	2015		2014
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	$	28,852	$	31,774
Noncurrent regulatory assets	477,279		480,192
Total	$	506,131	$	511,966

Schedule of Assumptions Used

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.66	%	4.11	%
Expected average long-term increase in compensation level	4.00		3.75
Mortality table	RP 2014		RP 2014

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.11	%	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75		3.75
Expected average long-term rate of return on assets	6.81		6.81		6.47

Components of Net Periodic Benefit Costs

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	28,260		$	23,939		$	25,206
Interest cost	50,857			53,277			46,160
Expected return on plan assets	(72,590		)	(70,709		)	(63,821		)
Amortization of prior service credit	(3,136		)	(3,092		)	(1,064		)
Amortization of net loss	36,377			33,892			43,418
Net periodic pension cost	39,768			37,307			49,899
Costs not recognized due to effects of regulation	(1,464		)	—			—
Net benefit cost recognized for financial reporting	$	38,304		$	37,307		$	49,899

Postretirement Benefit Plan

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	17,524	$	—		$	—	$	17,524
Government securities	—		35,016			—		35,016
Insurance contracts	—		42,123			—		42,123
Corporate bonds	—		65,031			—		65,031
Asset-backed securities	—		25,602			—		25,602
Mortgage-backed securities	—		31,778			—		31,778
Commingled funds	—		182,736			—		182,736
Other	—		(368		)	—		(368		)
Total	$	17,524	$	381,918		$	—	$	399,442

	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

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

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

	2015		2014
Domestic and international equity securities	25	%	25	%
Short-to-intermediate fixed income securities	57		57
Alternative investments	13		13
Cash	5		5
Total	100	%	100	%

Changes in Level 3 Plan Assets

For the years ended Dec. 31, 2015 and 2014, there were no assets transferred in or out of Level 3. The following table presents the changes in PSCo’s Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2013:

(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.

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)	2015			2014
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	443,753		$	508,971
Service cost	928			1,915
Interest cost	17,498			23,704
Medicare subsidy reimbursements	1,712			1,753
Plan participants’ contributions	4,961			4,625
Actuarial gain	(32,001		)	(63,130		)
Benefit payments	(33,277		)	(34,085		)
Obligation at Dec. 31	$	403,574		$	443,753

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	425,282		$	438,193
Actual (loss) return on plan assets	(3,076		)	11,060
Plan participants’ contributions	4,961			4,625
Employer contributions	5,552			5,489
Benefit payments	(33,277		)	(34,085		)
Fair value of plan assets at Dec. 31	$	399,442		$	425,282

Funded Status of Plans

(Thousands of Dollars)	2015			2014
Funded Status at Dec. 31:
Funded status (a)	$	(4,132	)	$	(18,471	)

^(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)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	49,226		$	56,823
Prior service credit	(33,942		)	(40,189		)
Total	$	15,284		$	16,634

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)	2015		2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Noncurrent regulatory assets	$	15,284	$	16,634

Schedule of Assumptions Used

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.65	%	4.08	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	6.00	%	6.50	%

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.08	%	4.82	%	4.10	%
Expected average long-term rate of return on assets	5.80		7.18		7.11

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	$	38,946	$	(33,136	)
Service and interest components	2,093		(1,743		)

Components of Net Periodic Benefit Costs

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	928		$	1,915		$	2,564
Interest cost	17,498			23,704			22,210
Expected return on plan assets	(23,803		)	(30,214		)	(29,227		)
Amortization of transition obligation	—			—			785
Amortization of prior service credit	(6,247		)	(6,247		)	(7,666		)
Amortization of net loss	2,475			6,434			13,699
Net periodic postretirement benefit (credit) cost	$	(9,149	)	$	(4,408	)	$	2,365

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Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

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

(Amounts in Thousands)(a)(b)	2015	2014
MWh of electricity	684	—
MMBtu of natural gas	12,515	735
Gallons of vehicle fuel	63	127

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

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

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)	2015			2014			2013
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,878	)	$	(23,338	)	$	(22,871	)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(30		)	(72		)	9
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	72			(468		)	(476		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23,836	)	$	(23,878	)	$	(23,338	)

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, 2015, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	54	(a)	$	—		$	—
Vehicle fuel and other commodity	(50		)	—			57		(b)	—			—
Total	$	(50	)	$	—		$	111		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	364		(c)
Natural gas commodity	—			(10,635		)	—			10,158		(e)	(7,620		)	(e)
Total	$	—		$	(10,635	)	$	—		$	10,158		$	(7,256	)

	Year Ended Dec. 31, 2014
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Gains 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 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	)

^(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, 2015 included $1.1 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, 2015, 2014 and 2013 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, 2015:

	Dec. 31, 2015
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	137	$	351	$	—	$	488	$	(324	)	$	164
Natural gas commodity	—		352		—		352		(286		)	66
Total current derivative assets	$	137	$	703	$	—	$	840	$	(610	)	230
PPAs (a)												1,715
Current derivative instruments												$	1,945
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	16	$	—	$	16	$	—		$	16
Total noncurrent derivative assets	$	—	$	16	$	—	$	16	$	—		16
PPAs (a)												3,462
Noncurrent derivative instruments												$	3,478
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	92	$	—	$	92	$	—		$	92
Other derivative instruments:
Commodity trading	34		325		—		359		(324		)	35
Natural gas commodity	—		3,850		—		3,850		(286		)	3,564
Total current derivative liabilities	$	34	$	4,267	$	—	$	4,301	$	(610	)	3,691
PPAs (a)												5,190
Current derivative instruments												$	8,881
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	33	$	—	$	33	$	—		$	33
Total noncurrent derivative liabilities	$	—	$	33	$	—	$	33	$	—		33
PPAs (a)												12,987
Noncurrent derivative instruments												$	13,020

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, PSCo qualified these contracts under the normal purchase exception.  Based 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, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents, for each of the fair value hierarchy levels, PSCo’s 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 on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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

Carrying Amount and Fair Value of Long-term Debt

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

	2015				2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,132,191	$	4,376,875	$	3,890,229	$	4,328,968

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Other Income, Net (Tables)

12 Months Ended

Dec. 31, 2015

Other Income and Expenses [Abstract]

Other Income, Net

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

(Thousands of Dollars)	2015			2014			2013
Interest income	$	753		$	1,470		$	1,761
Other nonoperating income	2,408			3,601			2,603
Insurance policy expense	(197		)	(806		)	(1,228		)
Other income, net	$	2,964		$	4,265		$	3,136

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Rate Matters (Tables)

12 Months Ended

Dec. 31, 2015

Public Utilities, General Disclosures [Abstract]

Colorado 2015 Multi-Year Gas Rate Case - Rebuttal Testimony

In July 2015, PSCo filed rebuttal testimony with adjustments and modified recovery between base rates and the PSIA rider. The revised request is summarized below:

(Millions of Dollars)	2015			2016 Step			2017 Step
PSCo’s filed base rate request	$	40.5		$	7.6		$	18.1
Shift O&M expenses between PSIA and base rates	—			7.0			6.4
Rebuttal corrections and adjustments	—			—			(7.7		)
Total base rate increase	$	40.5		$	14.6		$	16.8
Incremental PSIA rider revenues	(0.1		)	14.7			21.7
Total revenue impact from rebuttal	$	40.4		$	29.3		$	38.5
Requested ROE	10.1		%	10.1		%	10.3		%
Rate base	$	1,260		$	1,310		$	1,360

Colorado 2015 Multi-Year Gas Rate Case - Base Rate ALJ Recommendation and CPUC Deliberations

The following table reflects the ALJ’s position and the CPUC’s written order (estimated):

(Millions of Dollars)	ALJ			CPUC’s Written Order
PSCo’s filed 2015 base rate request (a)	$	40.5		$	40.5
ROE	(7.8		)	(7.8		)
Capital structure and cost of debt	(0.5		)	(0.5		)
Cherokee pipeline adjustment	4.1			4.1
Move to 2014 HTY	(14.1		)	(14.1		)
O&M expenses	(3.0		)	(2.4		)
Other, net	(1.1		)	(1.1		)
Overall recommended rate increase	$	18.1		$	18.7

^(a) The ALJ’s recommendation and the CPUC’s written order also includes approximately $20.0 million of PSIA costs be transferred to base rates, effective Jan. 1, 2016.

Colorado 2015 Multi-Year Gas Rate Case - PSIA Rider ALJ Recommendation and CPUC Deliberations

The ALJ’s recommendation, as well as the CPUC’s written order for the PSIA rider, are as follows (estimated):

	ALJ						CPUC’s Written Order
(Millions of Dollars)	2016			2017			2016			2017
PSCo’s filed incremental PSIA request	$	21.7		$	21.2		$	21.7		$	21.2
Transfer PSIA costs to base rates	(20.5		)	—			(20.5		)	—
PSIA cost recovery remaining in base	(4.3		)	—			(4.3		)	—
Projects not recovered through the PSIA	(3.6		)	(2.0		)	(3.3		)	(0.8		)
ROE and capital structure	(0.3		)	(1.6		)	(0.3		)	(1.6		)
Total	$	(7.0	)	$	17.6		$	(6.7	)	$	18.8

Colorado 2015 Multi-Year Gas Rate Case - Impact of CPUC Written Order

The following table summarizes the estimated annual pre-tax impact of the CPUC’s written order:

(Millions of Dollars)	2015			2016			2017
Base rate increase	$	18.7		$	19.7		$	—
Incremental PSIA rider revenues	(0.2		)	(6.7		)	18.8
Expense deferrals, net amortization (a)	(3.6		)	1.5			5.2
Estimated pre-tax impact	$	14.9		$	14.5		$	24.0

^(a) Deferral and amortization impacts relate primarily to recognition of accelerated amortization of prepaid pension assets and deferrals of pension expense in excess of the amount approved in the prior general gas rate case.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Estimated Minimum Purchases Under Fuel Contracts

The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2015, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2016	$	302.3	$	231.1	$	137.5
2017	230.3		129.5		137.2
2018	118.5		181.0		85.5
2019	42.0		187.6		51.0
2020	43.6		203.4		50.4
Thereafter	332.3		409.6		773.2
Total	$	1,069.0	$	1,342.2	$	1,234.8

Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements

At Dec. 31, 2015, 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)
2016	$	44.5	$	25.3
2017	24.3		4.4
2018	19.2		—
2019	10.3		—
2020	1.5		—
Thereafter	9.5		—
Total	$	109.3	$	29.7

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

Summary of Property Held Under Capital Leases

Total amortization expenses under capital lease assets were approximately $8.2 million, $7.2 million, and $6.3 million for 2015, 2014 and 2013, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(57.2		)	(49.0		)
Total property held under capital leases, net	$	164.0		$	172.2

Future Commitments Under Operating and Capital Leases

Future commitments under operating and capital leases are:

(Millions of Dollars)	Operating Leases		PPA (a) (b) Operating Leases		Total Operating Leases		Capital Leases
2016	$	12.0	$	102.2	$	114.2	$	29.3
2017	7.8		95.8		103.6		25.7
2018	7.4		96.0		103.4		25.3
2019	7.4		96.9		104.3		25.1
2020	7.4		97.7		105.1		24.9
Thereafter	39.5		579.7		619.2		486.5
Total minimum obligation							616.8
Interest component of obligation							(452.8		)
Present value of minimum obligation							$	164.0

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

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

Asset Retirement Obligations

A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2015 and 2014 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2015		Accretion		Cash Flow     Revisions (a)			Ending Balance      Dec. 31, 2015 (b)
Electric plant
Steam and other production asbestos	$	36,856	$	1,820	$	—		$	38,676
Steam and other production ash containment	61,885		2,769		6,113			70,767
Wind production	2,095		18		(121		)	1,992
Electric distribution	1,182		47		(99		)	1,130
Other	1,150		46		(142		)	1,054
Natural gas plant
Gas transmission and distribution	117,474		4,694		—			122,168
Other	3,886		153		(114		)	3,925
Common and other property
Common miscellaneous	768		28		—			796
Total liability	$	225,296	$	9,575	$	5,637		$	240,508

^(a)  In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above.

^(b)  There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow    Revisions (a)			Ending Balance  Dec. 31, 2014 (b)
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

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	29,260	$	497,973	$	32,195	$	500,889
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		144,953		—		141,214
Depreciation differences	1	One to sixteen years	14,221		99,835		10,700		104,743
Net AROs (b)	1, 12	Plant lives	—		62,948		—		46,213
Purchased power contract costs	12	Term of related contract	1,319		29,143		858		29,596
Property tax		One to six years	21,558		14,428		28,024		31,429
Contract valuation adjustments (c)	10	Term of related contract	9,376		9,526		8,901		12,999
Losses on reacquired debt	4	Term of related debt	1,421		6,957		1,426		8,378
Conservation programs (d)	1, 11	One to five years	8,466		6,947		10,198		10,906
Gas pipeline inspection costs	12	Less than one year	3,611		—		5,416		3,611
Recoverable purchased natural gas and electric energy costs	1	Less than one year	408		—		18,410		—
Other		Various	2,432		33,565		3,992		13,995
Total regulatory assets			$	92,072	$	906,275	$	120,120	$	903,973

^(a)  Includes $4.4 million and $4.5 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2015 and 2014, respectively.

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

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

^(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, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	364,291	$	—	$	366,359
Renewable resources and environmental initiatives	11, 12	Various	3,311		40,988		3,308		10,376
Investment tax credit deferrals	1, 7	Various	—		20,515		—		22,225
Deferred income tax adjustment	1	Various	—		16,891		—		18,672
PSCo earnings test	11	One to two years	42,868		9,472		57,127		42,819
Gas pipeline inspection costs	12	One to two years	1,140		4,273		13,970		642
Deferred electric, gas and steam production costs	1	Less than one year	66,696		—		24,035		—
Conservation programs (a)	1, 11	Less than one year	33,460		—		32,226		—
Low income discount program		Less than one year	1,393		—		1,680		—
Gain from asset sales		One to three years	—		—		316		4
Other		Various	3,955		14,991		1,797		3,324
Total regulatory liabilities (b)			$	152,823	$	471,421	$	134,459	$	464,421

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

^(b)  Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current

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Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2015

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, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2015			Year Ended Dec. 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)	$	(23,338	)
Other comprehensive loss before reclassifications	(30		)	(72		)
Losses (gains) reclassified from net accumulated other comprehensive loss	72			(468		)
Net current period other comprehensive income (loss)	42			(540		)
Accumulated other comprehensive loss at Dec. 31	$	(23,836	)	$	(23,878	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2015				Year Ended Dec. 31, 2014
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	54		(a)	$	(730	)	(a)
Vehicle fuel derivatives	57			(b)	(25		)	(b)
Total, pre-tax	111				(755		)
Tax expense	(39		)		287
Total amounts reclassified, net of tax	$	72			$	(468	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Results from Operations by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2015
Operating revenues (a)	$	3,115,257	$	1,006,666	$	41,590		$	—		$	4,163,513
Intersegment revenues	301		67		—			(368		)	—
Total revenues	$	3,115,558	$	1,006,733	$	41,590		$	(368	)	$	4,163,513
Depreciation and amortization	$	311,122	$	96,384	$	4,161		$	—		$	411,667
Interest charges and financing costs	136,397		34,935		576			—			171,908
Income tax expense (benefit)	234,873		44,192		(625		)	—			278,440
Net Income	391,257		74,267		1,278			—			466,802

(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

^(a)  Operating revenues include $13 million, $14 million and $13 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013, respectively. See Note 16 for further discussion of related party transactions by reportable segment.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

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)	2015		2014		2013
Operating revenues:
Electric	$	8,632	$	9,614	$	8,136
Other	4,441		4,441		4,441
Operating expenses:
Purchased power	—		23		1,331
Other operating expenses — paid to Xcel Energy Services Inc.	414,620		454,250		375,766
Interest expense	211		158		132
Interest income	45		61		273

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

	2015				2014
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	4,419	$	—	$	—	$	6,706
NSP-Wisconsin	71		—		22		—
SPS	414		—		5,803		—
Other subsidiaries of Xcel Energy Inc.	5		76,643		45,017		40,030
	$	4,909	$	76,643	$	50,842	$	46,736

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2015		June 30, 2015		Sept. 30, 2015		Dec. 31, 2015
Operating revenues	$	1,135,450	$	952,521	$	1,044,704	$	1,030,838
Operating income	215,400		195,176		315,174		173,951
Net income	110,966		98,500		173,081		84,255

	Quarter Ended
(Thousands of Dollars)	March 31, 2014		June 30, 2014		Sept. 30, 2014		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

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Number of DSM Products, Commercial and Industrial Customers	20
Number of DSM Products, Residential and Low-income Customers	23
DSM Measurements	1,000
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%	2.70%	2.80%
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

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Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$ 321,004	$ 346,007
Less allowance for bad debts	(20,122)	(23,122)
Accounts receivable, net	$ 300,882	$ 322,885

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Inventories	$ 205,562	$ 238,979
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	58,128	55,491
Fuel
Public Utilities, Inventory [Line Items]
Inventories	78,586	80,963
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 68,848	$ 102,525

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 16,586,427	$ 15,865,971
Less accumulated depreciation		(4,414,216)	(4,239,015)
Property, plant and equipment, net		12,172,211	11,626,956
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		11,856,126	10,927,867
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		3,420,249	3,210,242
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		862,840	827,708
Plant to be retired
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	[1]	38,249	71,534
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 408,963	$ 828,620

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

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Amount outstanding at period end	$ 14,000	$ 14,000	$ 382,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000	250,000	250,000	$ 250,000
Amount outstanding at period end	0	0	0	0
Average amount outstanding	4,000	1,000	4,000	0
Maximum amount outstanding	$ 34,000	$ 34,000	$ 97,000	$ 12,000
Weighted average interest rate, computed on a daily basis (percentage)	0.36%	0.41%	0.25%	0.36%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 700,000	$ 700,000	$ 700,000	$ 700,000
Amount outstanding at period end	14,000	14,000	382,000	0
Average amount outstanding	14,000	95,000	167,000	38,000
Maximum amount outstanding	$ 68,000	$ 449,000	$ 393,000	$ 332,000
Weighted average interest rate, computed on a daily basis (percentage)	0.50%	0.51%	0.31%	0.34%
Weighted average interest rate at period end (percentage)	0.60%	0.60%	0.65%

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 14,000	$ 382,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 4,000	$ 6,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

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Borrowings and Other Financing Instruments, Credit Facility (Details) - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio		45.00%	47.00%
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]
Debt Instrument, Term		5 years
Credit Facility		$ 700,000,000
Drawn	[1]	18,000,000
Available		682,000,000
Direct advances on the credit facility outstanding		$ 0
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit		0.075%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit		0.275%
Eurodollar [Member] | Credit Facility
Line of Credit Facility [Line Items]
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings		0.875%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings		1.75%

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

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Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Long-Term Borrowings [Line Items]
Long-term Line of Credit			$ 0
Deferred Finance Costs, Noncurrent, Net		$ 26,600,000	26,500,000
First Mortgage Bonds | Series Due May 15, 2025 [Member]
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)		2.90%
Maturity date		May 15, 2025
Long-term Debt, Gross		$ 250,000,000	0
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	$ 300,000,000
First Mortgage Bonds | Series Due Sept. 1, 2017
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)		4.375%	4.375%
Maturity date		Sep. 01, 2017	Sep. 01, 2017
Long-term Debt, Gross	[1]	$ 129,500,000	$ 129,500,000
First Mortgage Bonds | Series Due Aug. 1, 2018
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)		5.80%	5.80%
Maturity date		Aug. 01, 2018	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%	5.125%
Maturity date		Jun. 01, 2019	Jun. 01, 2019
Long-term Debt, Gross		$ 400,000,000	$ 400,000,000
First Mortgage Bonds | Series Due Nov. 15, 2020
Long-Term Borrowings [Line Items]
Interest rate, stated percentage (in hundredths)		3.20%	3.20%
Maturity date		Nov. 15, 2020	Nov. 15, 2020
Long-term Debt, Gross		$ 400,000,000	$ 400,000,000
PSCo [Member] | First Mortgage Bonds | Series Due May 15, 2025 [Member]
Long-Term Borrowings [Line Items]
Face amount		$ 250,000,000
Interest rate, stated percentage (in hundredths)		2.90%

[1] Pollution control financing.

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Preferred Stock (Details)	Dec. 31, 2015 $ / shares shares
Equity [Abstract]
Preferred stock, shares authorized (in shares)	10,000,000
Preferred stock, par value (in dollars per share) | $ / shares	$ 0.01
Preferred stock, shares outstanding (in shares)	0

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Joint Ownership of Generation, Transmission and Gas Facilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) MW
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 1,508,884
Accumulated depreciation	370,531
Construction work in progress	$ 37,182
Generating capacity (in MW) | MW	820
Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 155,159
Accumulated depreciation	69,679
Construction work in progress	$ 147
Ownership percentage (in hundredths)	76.00%
Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 121,486
Accumulated depreciation	61,780
Construction work in progress	$ 20,840
Ownership percentage (in hundredths)	37.00%
Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 37,756
Accumulated depreciation	17,910
Construction work in progress	$ 321
Ownership percentage (in hundredths)	53.00%
Electric Generation | Craig Units 1 and 2
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 60,158
Accumulated depreciation	36,570
Construction work in progress	$ 8,518
Ownership percentage (in hundredths)	10.00%
Electric Generation | Craig Common Facilities 1, 2 and 3
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 37,418
Accumulated depreciation	18,520
Construction work in progress	$ 505
Ownership percentage (in hundredths)	7.00%
Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 892,340
Accumulated depreciation	95,029
Construction work in progress	$ 452
Ownership percentage (in hundredths)	67.00%
Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 23,826
Accumulated depreciation	1,430
Construction work in progress	$ 894
Ownership percentage (in hundredths)	82.00%
Electric Transmission | Transmission and other facilities, including substations
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 152,460
Accumulated depreciation	62,324
Construction work in progress	$ 5,378
Ownership percentage of group of jointly owned facilities	Various
Gas Transportation | Rifle to Avon
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 19,928
Accumulated depreciation	7,165
Construction work in progress	$ 0
Ownership percentage (in hundredths)	60.00%
Gas Transportation | Gas Transportation Compressor [Member]
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 8,353
Accumulated depreciation	124
Construction work in progress	$ 127
Ownership percentage (in hundredths)	50.00%

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Income Taxes (Details)	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2015 USD ($) $ / kWh	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Consolidated Appropriations Act of 2016 [Abstract]
Excise Tax Delay	2 years
Tax Increase Prevention Act of 2014 [Abstract]
Number of years bonus depreciation was extended		1 year	1 year
American Taxpayer Relief Act of 2012 [Abstract]
Original top tax rate for dividends							15.00%
New top tax rate for dividends							20.00%
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions					$ 2,400,000	$ 1,900,000
Unrecognized tax benefit — Temporary tax positions					15,000,000	10,000,000
Total unrecognized tax benefit	$ 11,900,000	$ 8,400,000	$ 9,600,000	$ 9,600,000	17,400,000	11,900,000	$ 8,400,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1	11,900,000	8,400,000	9,600,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	4,500,000	3,700,000	3,900,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	(1,500,000)	(700,000)	0
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions	2,500,000	2,800,000	3,300,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions	0	(1,200,000)	(900,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	0	(1,100,000)	(7,500,000)
Balance at Dec. 31	$ 17,400,000	$ 11,900,000	$ 8,400,000	$ 9,600,000
Tax Benefits Associated With Nol And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards					(4,300,000)	(3,900,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible					11,000,000
Amounts accrued for penalties related to unrecognized tax benefits					0	0	$ 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	3.20%	2.80%	3.00%
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent	0.10%	(0.10%)	0.10%
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent	(0.30%)	(2.10%)	(1.40%)
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	(0.70%)	(0.80%)	(0.80%)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent	0.10%	0.10%	(0.30%)
Effective Income Tax Rate Reconciliation, Percent	37.40%	34.90%	35.60%
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ (1,166,000)	$ 9,550,000	$ (52,408,000)
Current State and Local Tax Expense (Benefit)	(727,000)	2,611,000	(7,252,000)
Current Change In Unrecognized Tax Expense (Benefit)	5,244,000	6,548,000	(2,918,000)
Deferred Federal Income Tax Expense (Benefit)	246,096,000	208,781,000	273,916,000
Deferred State and Local Income Tax Expense (Benefit)	36,450,000	26,196,000	38,243,000
Deferred Change In Unrecognized Tax Expense (Benefit)	(4,650,000)	(7,154,000)	4,094,000
Deferred investment tax credits	(2,807,000)	(2,941,000)	(2,935,000)
Income Tax Expense (Benefit)	278,440,000	243,591,000	250,740,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items	285,144,000	254,142,000	335,580,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(7,229,000)	(26,649,000)	(19,616,000)
Other Comprehensive Income (Loss), Tax	(19,000)	330,000	289,000
Deferred Income Tax Expense (Benefit)	$ 277,896,000	$ 227,823,000	$ 316,253,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment					2,772,043,000	2,467,260,000
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits					105,049,000	110,556,000
Deferred Tax Liabilities, Other					101,219,000	140,080,000
Deferred Tax Liabilities, Net					2,658,198,000	2,373,054,000
Deferred Tax Liabilities, Gross					2,978,311,000	2,717,896,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards					147,763,000	143,158,000
Deferred Tax Assets Unbilled Revenue Fuel Costs					48,181,000	57,654,000
Deferred Tax Assets Rate Refund					23,352,000	43,735,000
Deferred Tax Assets Tax credit carryforward					35,240,000	34,493,000
Deferred Tax Assets Regulatory Liabilities					17,201,000	14,549,000
Deferred Tax Assets Deferred Investment Tax Credits					12,718,000	13,781,000
Deferred Tax Assets, Other					35,658,000	37,472,000
Deferred Tax Assets, Net of Valuation Allowance					320,113,000	344,842,000
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination	2012 and 2013			2010 and 2011
Year of carryback claim under examination	2009
Potential Tax Adjustments	$ 14,000,000
Operating Loss Carryforwards					328,000,000	320,000,000
Tax Credit Carryforward, Amount					24,000,000	22,000,000
Carryforward expiration date range, low	2021
Carryforward expiration date range, high	2035
State and Local Jurisdiction
Tax Audits [Abstract]
Earliest year subject to examination	2009
Operating Loss Carryforwards					684,000,000	690,000,000
Tax Credit Carryforward Net Of Federal Detriment					13,000,000	12,000,000
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit					(1,000,000)	0
Federal detriment					7,000,000	$ 7,000,000
Federal Benefit					$ 1,000,000
Carryforward expiration date range, low	2017
Carryforward expiration date range, high	2033
Consolidated Appropriations Act of 2016; 2015, 2016, 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent					50.00%
Consolidated Appropriations Act of 2016; 2018 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent					40.00%
Production Tax Credit Rate, Percent					60.00%
Consolidated Appropriations Act of 2016; 2019 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent					30.00%
Production Tax Credit Rate, Percent					40.00%
Investment Tax Credit Rate, Percent					30.00%
Consolidated Appropriations Act of 2016; 2016 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent					100.00%
Production Tax Credit per KWh | $ / kWh					0.023
Consolidated Appropriations Act of 2016; 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent					80.00%
Consolidated Appropriations Act of 2016; 2020 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent					26.00%
Consolidated Appropriations Act of 2016; 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent					22.00%
Consolidated Appropriations Act of 2016; After 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent					10.00%
Tax Increase Prevention Act of 2014; 2014 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent						50.00%
Tax Increase Prevention Act of 2014; 2015 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent					50.00%
American Taxpayer Relief Act of 2012; 2013 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent							50.00%
American Taxpayer Relief Act of 2012; 2014 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent						50.00%

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Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2015 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 (as a percent)	77.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	2,024

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Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2015
Commingled funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	1 day
Commingled funds | Maximum
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
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days

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Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 3,600	$ 3,800
Net benefit cost recognized for financial reporting	600	600
Pension Plans
Pension Benefits [Abstract]
Total benefit obligation	1,224,650	1,277,957	$ 1,152,836
Net benefit cost recognized for financial reporting	$ 38,304	$ 37,307	$ 49,899
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 (as a percent)	6.81%	6.81%	6.47%
Expected average long-term rate of return on assets for next fiscal year (as a percent)	6.84%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Pension Plans | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	36.00%	32.00%
Pension Plans | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	32.00%	35.00%
Pension Plans | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	12.00%	12.00%
Pension Plans | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	18.00%	18.00%
Pension Plans | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	2.00%	3.00%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 41,800	$ 46,500
Net benefit cost recognized for financial reporting	$ 9,500	$ 4,700

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Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 1,036,681	$ 1,103,865	$ 1,067,057
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	110,751	119,553
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	872,896	915,692
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	53,034	68,620	64,578	$ 82,991
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	81,954	82,486
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	81,954	82,486
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	1,204	508
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	1,204	508
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	214,341	180,912
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	214,341	180,912
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	86,914	115,593
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	86,914	115,593
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	881	1,360
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	881	1,360
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	0	4,604
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
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
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
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
Common stock
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	28,797	37,067
Common stock | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	28,797	37,067
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	34,353	50,210
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	34,353	50,210	49,022	47,056
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	573,009	629,439
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	573,009	629,439
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	18,681	18,410	15,556
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	18,681	18,410	$ 15,556	$ 19,273
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	(3,453)	(16,117)
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	(3,453)	(16,117)
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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Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Pension Plan Assets (Details) - Pension Plans - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		$ 1,103,865	$ 1,067,057
Fair value of plan assets at Dec. 31		1,036,681	1,103,865	$ 1,067,057
Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		68,620	64,578	82,991
Net realized gains (losses)		9,561	9,675	6,204
Net unrealized gains (losses)		(22,407)	(4,601)	(258)
Purchases, issuances and settlements, net		(2,740)	(1,032)	1,967
Transfers in (out) of Level 3		0	0	(26,326)	[1]
Fair value of plan assets at Dec. 31		53,034	68,620	64,578
Asset-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		1,360
Fair value of plan assets at Dec. 31		881	1,360
Asset-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	4,604
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(4,604)
Fair value of plan assets at Dec. 31		0	0	0
Mortgage-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		3,997
Fair value of plan assets at Dec. 31			3,997
Mortgage-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	12,058
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(12,058)
Fair value of plan assets at Dec. 31			0	0
Private equity investments
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		50,210
Fair value of plan assets at Dec. 31		34,353	50,210
Private equity investments | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		50,210	49,022	47,056
Net realized gains (losses)		7,636	8,495	7,074
Net unrealized gains (losses)		(20,036)	(4,299)	(4,027)
Purchases, issuances and settlements, net		(3,457)	(3,008)	(1,081)
Transfers in (out) of Level 3		0	0	0	[1]
Fair value of plan assets at Dec. 31		34,353	50,210	49,022
Real estate
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		18,410	15,556
Fair value of plan assets at Dec. 31		18,681	18,410	15,556
Real estate | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		18,410	15,556	19,273
Net realized gains (losses)		1,925	1,180	(870)
Net unrealized gains (losses)		(2,371)	(302)	3,769
Purchases, issuances and settlements, net		717	1,976	3,048
Transfers in (out) of Level 3		0	0	(9,664)	[1]
Fair value of plan assets at Dec. 31		$ 18,681	$ 18,410	$ 15,556

[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, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - Pension Plans $ in Thousands		1 Months Ended	12 Months Ended
		Jan. 31, 2016 USD ($) Plan	Dec. 31, 2015 USD ($) Plan	Dec. 31, 2014 USD ($) Plan	Dec. 31, 2013 USD ($) Plan
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			$ 1,192,798	$ 1,249,739
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 1,224,650	1,277,957	1,152,836
Service cost			28,260	23,939	$ 25,206
Interest cost			50,857	53,277	46,160
Transfer (to) from other plan			(2,938)	(13,404)
Actuarial (gain) loss			(54,737)	133,215
Benefit payments			(74,749)	(71,906)
Obligation at Dec. 31			1,224,650	1,277,957	1,152,836
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		1,036,681	1,103,865	1,067,057
Actual return (loss) on plan assets			(9,122)	84,871
Employer contributions			20,056	35,156
Transfer (to) from other plan			(3,369)	(11,313)
Benefit payments			(74,749)	(71,906)
Fair value of plan assets at Dec. 31			1,036,681	1,103,865	1,067,057
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]		(187,969)	(174,092)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			521,703	530,674
Prior service (credit) cost			(15,572)	(18,708)
Total			506,131	511,966
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			28,852	31,774
Noncurrent regulatory assets			477,279	480,192
Total			$ 506,131	$ 511,966
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Measurement date			Dec. 31, 2015	Dec. 31, 2014
Discount rate for year-end valuation (as a percent)			4.66%	4.11%
Expected average long-term increase in compensation level (as a percent)			4.00%	3.75%
Mortality table			RP 2014	RP 2014
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 20,100	$ 35,200	44,600
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			28,260	23,939	25,206
Interest cost			50,857	53,277	46,160
Expected return on plan assets			(72,590)	(70,709)	(63,821)
Amortization of prior service (credit) cost			(3,136)	(3,092)	(1,064)
Amortization of net loss			36,377	33,892	43,418
Net periodic benefit cost			39,768	37,307	49,899
Costs not recognized due to regulation			(1,464)	0	0
Net benefit cost recognized for financial reporting			$ 38,304	$ 37,307	$ 49,899
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.11%	4.75%	4.00%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%	3.75%
Expected average long-term rate of return on assets (as a percent)			6.81%	6.81%	6.47%
Allocated costs for pension plans sponsored by Xcel Energy Inc.			$ 9,900	$ 9,400	$ 11,600
Expected average long-term rate of return on assets for next fiscal year (as a percent)			6.84%
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 (as a percent)			20.00%
Xcel Energy Inc.
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan			4	4	4
Total contributions to Xcel Energy's pension plans during the period			$ 90,100	$ 130,600	$ 192,400
Subsequent Event
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 16,800
Subsequent Event | Xcel Energy Inc.
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan		4
Total contributions to Xcel Energy's pension plans during the period		$ 125,000

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

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Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 9.5	$ 9.1	$ 8.7

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Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Postretirement Benefit Plan	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	25.00%	25.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	57.00%	57.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	13.00%	13.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	5.00%	5.00%

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Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefit Plan - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 399,442	$ 425,282		$ 438,193
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	17,524	23,566
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	381,918	401,716
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0		0	$ 36,064
Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Cash collateral restricted for use		900
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	17,524	23,566	[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	17,524	23,566	[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	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	0	[1]
Derivatives
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		166
Derivatives | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		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
Derivatives | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	35,016	43,494
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	35,016	43,494
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	42,123	45,075
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	42,123	45,075
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	65,031	48,527
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	65,031	48,527
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	25,602	3,240		0
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	25,602	3,240
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
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	31,778	10,071
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	31,778	10,071
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		$ 0	$ 35,394
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	182,736	252,790
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	182,736	252,790
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	(368)	(1,647)
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	(368)	(1,647)
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 at Dec. 31, 2014.

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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		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		$ 425,282	$ 438,193
Fair value of plan assets at Dec. 31		399,442	425,282	$ 438,193
Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	36,064
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(36,064)
Fair value of plan assets at Dec. 31		0	0	0
Asset-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		3,240	0
Fair value of plan assets at Dec. 31		25,602	3,240	0
Asset-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0		670
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(670)
Fair value of plan assets at Dec. 31		0	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		31,778	10,071
Mortgage-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	35,394
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(35,394)
Fair value of plan assets at Dec. 31		$ 0	$ 0	$ 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, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - Postretirement Benefit Plan - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 443,753	$ 508,971
Service cost		928	1,915	$ 2,564
Interest cost		17,498	23,704	22,210
Medicare subsidy reimbursements		1,712	1,753
Plan participants' contributions		4,961	4,625
Actuarial (gain) loss		(32,001)	(63,130)
Benefit payments		(33,277)	(34,085)
Obligation at Dec. 31		403,574	443,753	508,971
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		425,282	438,193
Actual return (loss) on plan assets		(3,076)	11,060
Plan participants' contributions		4,961	4,625
Employer contributions		5,552	5,489
Benefit payments		(33,277)	(34,085)
Fair value of plan assets at Dec. 31		399,442	425,282	438,193
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]	(4,132)	(18,471)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		49,226	56,823
Prior service (credit) cost		(33,942)	(40,189)
Total		15,284	16,634
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Noncurrent regulatory assets		$ 15,284	$ 16,634
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Measurement date		12/31/2015	12/31/2014
Discount rate for year-end valuation (as a percent)		4.65%	4.08%
Mortality table		RP 2014	RP 2014
Health care costs trend rate - initial (as a percent)		6.00%	6.50%
Ultimate health care trend assumption rate (as a percent)		4.50%	4.50%
Period until ultimate trend rate is reached (in years)		3 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO		$ 38,946
One-percent decrease in APBO		(33,136)
One-percent increase in service and interest components		2,093
One-percent decrease in service and interest components		(1,743)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		5,600	$ 5,500	7,000
Expected contribution to postretirement health care plans during 2016		0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		928	1,915	2,564
Interest cost		17,498	23,704	22,210
Expected return on plan assets		(23,803)	(30,214)	(29,227)
Amortization of transition obligation		0	0	785
Amortization of prior service (credit) cost		(6,247)	(6,247)	(7,666)
Amortization of net loss		2,475	6,434	13,699
Net periodic benefit cost		$ (9,149)	$ (4,408)	$ 2,365
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		4.08%	4.82%	4.10%
Expected average long-term rate of return on assets (as a percent)		5.80%	7.18%	7.11%
Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		$ 18,300	$ 17,100	$ 17,600
Expected contribution to postretirement health care plans during 2016		$ 12,300

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

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Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Pension Plans
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2016	$ 77,898
2017	77,952
2018	80,583
2019	82,760
2020	83,372
2021-2025	430,762
Postretirement Benefit Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2016	32,197
2017	32,356
2018	32,381
2019	32,402
2020	33,093
2021-2025	158,040
Expected Medicare Part D Subsidies [Abstract]
2016	2,234
2017	2,373
2018	2,517
2019	2,647
2020	2,753
2021-2025	15,450
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2016	29,963
2017	29,983
2018	29,864
2019	29,755
2020	30,340
2021-2025	$ 142,590

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions		Dec. 31, 2015 USD ($) gal MWh MMBTU Counterparty	Dec. 31, 2014 gal MWh MMBTU
Commodity Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months		$ (0.1)
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		10
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		9
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		3
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 1.2
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		2.00%
Credit Concentration Risk | 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 | Counterparty		6
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 33.2
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		48.00%
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 4.9
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		7.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months		$ (1.0)
Electric Commodity
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1],[2]	684	0
Natural Gas Commodity
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	12,515	735
Vehicle Fuel Commodity
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | gal	[1],[2]	63	127

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

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

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Other Income, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Income and Expenses [Abstract]
Interest income	$ 753	$ 1,470	$ 1,761
Other nonoperating income	2,408	3,601	2,603
Insurance Policy Expense (Income), Net	(197)	(806)	(1,228)
Other income, net	$ 2,964	$ 4,265	$ 3,136

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Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ (23,878)	$ (23,338)	$ (22,871)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges	(30)	(72)	9
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	72	(468)	(476)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ (23,836)	$ (23,878)	$ (23,338)

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
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 | Cash Flow Hedges
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		(50,000)		(115,000)		14,000
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		111,000		(755,000)		(770,000)
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 | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0		0		0
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	[1]	54,000		(730,000)		(730,000)
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 | Cash Flow Hedges | Vehicle Fuel And Other Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		(50,000)		(115,000)		14,000
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	[2]	57,000		(25,000)		(40,000)
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
Other Derivative Instruments
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(10,635,000)		451,000		(4,001,000)
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)		10,158,000		(4,631,000)		4,340,000
Pre-tax gains (losses) recognized during the period in income		(7,256,000)		(9,850,000)		(5,850,000)
Other Derivative Instruments | Commodity Trading
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0
Pre-tax gains (losses) recognized during the period in income	[3]	364,000
Other Derivative Instruments | Natural Gas Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(10,635,000)		451,000		(4,001,000)
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]	10,158,000		(4,631,000)		4,340,000
Pre-tax gains (losses) recognized during the period in income		(7,620,000)	[4]	$ (9,850,000)	[4]	$ (5,850,000)	[5]
Other Derivative Instruments | Natural Gas Commodity for Electric Generation
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)		$ 1,100,000

[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, 2015 included $1.1 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, 2015, 2014 and 2013 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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Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 0	$ 0
Collateral posted on derivative instruments	0	0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2015		Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		$ 0		$ 0
Derivative Asset, Collateral, Obligation to Return Cash, Offset		0		0
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,945		1,731
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3,478		5,176
Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		8,881		5,774
Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		13,020		18,257
Fair Value Measured on a Recurring Basis | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		230		15
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		164
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		66		15
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		3,691		583
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		92		53
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		35
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		3,564		530
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		33		81
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				46
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		33
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				35
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		137		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		137
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other 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] | Other Derivative Instruments | 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 Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		34		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		34
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | 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] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		703		33
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		351
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		352		33
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		4,267		601
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		92		53
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		325
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		3,850		548
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		33		81
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				46
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		33
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				35
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] | Other Derivative Instruments | 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 | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other 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] | Other Derivative Instruments | 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 Liabilities [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] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading
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 | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | 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] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		840		33
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		488
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		352		33
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		16
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		4,301		601
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		92		53
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		359
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		3,850		548
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		33		81
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				46
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		33
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				35
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(610)	[1]	(18)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	(324)
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		(286)	[1]	(18)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	0
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	0
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(610)	[1]	(18)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[1]	(324)
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(286)	[1]	(18)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]			0
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[1]	0
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]			0
Fair Value, Measurements, Nonrecurring [Member] | Other Current Assets [Member] | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,715	[3]	1,716	[4]
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Assets [Member] | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3,462	[3]	5,176	[4]
Fair Value, Measurements, Nonrecurring [Member] | Other Current Liabilities [Member] | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		5,190	[3]	5,191	[4]
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Liabilities [Member] | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		$ 12,987	[3]	$ 18,176	[4]

[1] PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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

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

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

XML

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,132,191	$ 3,890,229
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,376,875	$ 4,328,968

XML

Rate Matters (Details) $ in Thousands	1 Months Ended						12 Months Ended
	Feb. 29, 2016 USD ($)	Dec. 31, 2015 USD ($)	Nov. 30, 2015 USD ($)	Jul. 31, 2015 USD ($)	Mar. 31, 2015 USD ($)	Feb. 28, 2015	Dec. 31, 2015 USD ($) MWh	Dec. 31, 2014 USD ($) MWh	Dec. 31, 2012 USD ($)	Dec. 31, 2011
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Original Request - Gas Rates PSIA Rider 2016
Rate Matters [Abstract]
Public Utilities, Revenue Impact Of Requested Rider					$ 21,700
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Original Request - Gas Rates PSIA Rider 2017
Rate Matters [Abstract]
Public Utilities, Revenue Impact Of Requested Rider					21,200
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 66,200
Public Utilities, Number Of Years Rate Case Is Applicable For					3 years
Public Utilities, Requested Equity Capital Structure, Percentage					56.00%
Public Utilities, Requested Return on Equity, Percentage					10.10%
Public Utilities, Requested Rate Base, Amount					$ 1,260
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					40,500
Public Utilities, Increase in Request By Shift in O&M Expenses Between Rider And Base Rates				$ 0
Public Utilities, Decrease in Request by Corrections And Adjustments Based On Rebuttal Testimony				0
Public Utilities, Revised Base Rate Request From Rebuttal Testimony				40,500
Public Utilities, Total Revenue Impact From Rebuttal Testimony				40,400
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 7,600
Public Utilities, Increase in Request By Shift in O&M Expenses Between Rider And Base Rates				7,000
Public Utilities, Decrease in Request by Corrections And Adjustments Based On Rebuttal Testimony				0
Public Utilities, Revised Base Rate Request From Rebuttal Testimony				14,600
Public Utilities, Total Revenue Impact From Rebuttal Testimony				29,300
Public Utilities, Requested Return on Equity, Percentage					10.10%
Public Utilities, Requested Rate Base, Amount					$ 1,310
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2017
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 18,100
Public Utilities, Increase in Request By Shift in O&M Expenses Between Rider And Base Rates				6,400
Public Utilities, Decrease in Request by Corrections And Adjustments Based On Rebuttal Testimony				(7,700)
Public Utilities, Revised Base Rate Request From Rebuttal Testimony				16,800
Public Utilities, Total Revenue Impact From Rebuttal Testimony				38,500
Public Utilities, Requested Return on Equity, Percentage					10.30%
Public Utilities, Requested Rate Base, Amount					$ 1,360
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider
Rate Matters [Abstract]
Public Utilities, Number Of Years Rate Case Is Applicable For					3 years
Public Utilities, Revenue Impact Of Requested Rider					$ 42,800
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2015
Rate Matters [Abstract]
Public Utilities, Revenue Impact Of Requested Rider				(100)
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016
Rate Matters [Abstract]
Public Utilities, Revenue Impact Of Requested Rider				14,700
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017
Rate Matters [Abstract]
Public Utilities, Revenue Impact Of Requested Rider				21,700
Colorado 2015 Steam Rate Case
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 3,500
Colorado 2015 Steam Rate Case, Phase 1 - Jan. 1, 2016
Rate Matters [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 2,800
Colorado 2015 Steam Rate Case, Phase 2 - Nov. 1, 2016
Rate Matters [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount		700
CPUC Proceeding - Annual Electric Earnings Test 2015 through 2017
Rate Matters [Abstract]
Public Utilities, Return on Equity Threshold for Earnings Sharing						9.83%
2015 Electric Earnings Test
Rate Matters [Abstract]
Public Utilities, Refund to Customers Due to Annual Earnings Test							$ 15,000
CPUC Proceeding - Demand Side Management Cost Adjustment
Rate Matters [Abstract]
Public Utilities, Incentive Award Upon Achieving Savings Goal							$ 5,000
Public Utilities, Percentage of Net Economic Benefits on Which Incentive is Earned							5.00%
Public Utilities, Maximum Annual Incentive							$ 30,000
CPUC Proceeding - Demand Side Management Cost Adjustment, 2015
Rate Matters [Abstract]
Public Utilities, Approved Electric Demand Side Management Budget				81,600
Public Utilities, Approved Gas Demand Side Management Budget				13,100
CPUC Proceeding - Demand Side Management Cost Adjustment, 2016
Rate Matters [Abstract]
Public Utilities, Approved Electric Demand Side Management Budget				78,700
Public Utilities, Approved Gas Demand Side Management Budget				$ 13,600
CPUC Proceeding - Renewable Energy Credit Sharing
Rate Matters [Abstract]
Public Utilities, Customers Share of Margins Credited Against RESA Regulatory Asset Balance							5,500	$ 600
Public Utilities, Cumulative Credit Against RESA Regulatory Asset Balance		$ 110,600					$ 110,600	$ 105,100
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case
Rate Matters [Abstract]
Public Utilities, Recommended Length Of Average Rate Base By Third Parties (in Months)			13
Public utilities, ROE recommended by third parties			9.50%
Public Utilities, Recommended Equity Capital Structure, Percentage			56.51%
Public Utilities, Proposed Number of Years Extending PSIA Rider Recommended by Third Parties			3 years
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015
Rate Matters [Abstract]
Public Utilities, Decrease to Requested Return on Equity			$ (7,800)
Public Utilities, Decrease to Cost of Debt and Capital Structure			(500)
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment			4,100
Public Utilities, Decrease in Move to Historical Test Year			(14,100)
Public Utilities, Decrease to O&M Expenses			(3,000)
Public Utilities, Decrease Related To Other, Net			(1,100)
Public Utilities, Recommended Rate Increase (Decrease), Amount			18,100
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016
Rate Matters [Abstract]
Public Utilities, Recommended Rider Costs to be Recovered Through Base Rates, Amount			20,000
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016
Rate Matters [Abstract]
Public Utilities, Decrease in Request by Transfer Of Costs To Base Rates			(20,500)
Public Utilities, Decrease in Request By Cost Recovery Remaining In Base			(4,300)
Public Utilities, Decrease In Request For Projects Not Recovered Through The Rider			(3,600)
Public Utilities, Decrease to Return on Equity and Capital Structure			(300)
Public Utilities, Recommended Rider Increase (Decrease)			(7,000)
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017
Rate Matters [Abstract]
Public Utilities, Decrease in Request by Transfer Of Costs To Base Rates			0
Public Utilities, Decrease in Request By Cost Recovery Remaining In Base			0
Public Utilities, Decrease In Request For Projects Not Recovered Through The Rider			(2,000)
Public Utilities, Decrease to Return on Equity and Capital Structure			(1,600)
Public Utilities, Recommended Rider Increase (Decrease)			$ 17,600
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Demand Side Management Cost Adjustment, 2014
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (in MWh) | MWh								384
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Demand Side Management Cost Adjustment, 2015
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (in MWh) | MWh							400
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
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 REC Margin Limit Approved									20.00%
Public Utilities, Percentage of Margin in Excess of REC Margin Limit Approved									10.00%
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 REC Margin Limit Approved									80.00%
Public Utilities, Percentage of Margin in Excess of REC Margin Limit Approved									90.00%
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Demand Side Management Cost Adjustment, 2016 through 2020
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (in MWh) | MWh							400
Public Utilities, Annual Spending Limit							$ 84,300
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case
Rate Matters [Abstract]
Public Utilities, Approved Length Of Average Rate Base By Third Parties (in Months)	13
Public Utilities, Approved Return on Equity, Percentage	9.50%
Public Utilities, Approved Equity Capital Structure, Percentage	56.51%
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015
Rate Matters [Abstract]
Public Utilities, Decrease to Approved Return on Equity	$ (7,800)
Public Utilities, Decrease to Cost of Debt and Capital Structure	(500)
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment	4,100
Public Utilities, Decrease in Move to Historical Test Year	(14,100)
Public Utilities, Decrease to O&M Expenses	(2,400)
Public Utilities, Decrease Related To Other, Net	(1,100)
Public Utilities, Approved Rate Increase (Decrease), Amount	18,700
Public Utilities, Increase (Decrease) In Estimated Pre-Tax Impact For Expense Deferrals, Net Amortization	(3,600)
Public Utilities, Estimated Pre-Tax Impact	14,900
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016
Rate Matters [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	19,700
Public Utilities, Approved Rider Costs To Be Recovered Through Base Rates, Amount	20,000
Public Utilities, Increase (Decrease) In Estimated Pre-Tax Impact For Expense Deferrals, Net Amortization	1,500
Public Utilities, Estimated Pre-Tax Impact	14,500
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2017
Rate Matters [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	0
Public Utilities, Increase (Decrease) In Estimated Pre-Tax Impact For Expense Deferrals, Net Amortization	5,200
Public Utilities, Estimated Pre-Tax Impact	24,000
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2015
Rate Matters [Abstract]
Public Utilities, Approved Rider Increase (Decrease)	(200)
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016
Rate Matters [Abstract]
Public Utilities, Decrease To Written Order By Transfer Of Costs To Base Rates	(20,500)
Public Utilities, Decrease to Written Order By Cost Recovery Remaining In Base	(4,300)
Public Utilities, Decrease To Written Order For Projects Not Recovered Through The Rider	(3,300)
Public Utilities, Decrease To Written Order For Approved Return on Equity and Capital Structure	(300)
Public Utilities, Approved Rider Increase (Decrease)	(6,700)
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017
Rate Matters [Abstract]
Public Utilities, Decrease To Written Order By Transfer Of Costs To Base Rates	0
Public Utilities, Decrease to Written Order By Cost Recovery Remaining In Base	0
Public Utilities, Decrease To Written Order For Projects Not Recovered Through The Rider	(800)
Public Utilities, Decrease To Written Order For Approved Return on Equity and Capital Structure	(1,600)
Public Utilities, Approved Rider Increase (Decrease)	$ 18,800

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Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date (year)	2016
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date (year)	2060
Coal
Fuel Contracts [Abstract]
2016	$ 302.3
2017	230.3
2018	118.5
2019	42.0
2020	43.6
Thereafter	332.3
Total	1,069.0
Natural Gas Supply
Fuel Contracts [Abstract]
2016	231.1
2017	129.5
2018	181.0
2019	187.6
2020	203.4
Thereafter	409.6
Total	1,342.2
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2016	137.5
2017	137.2
2018	85.5
2019	51.0
2020	50.4
Thereafter	773.2
Total	$ 1,234.8

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Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Long-term Contract for Purchase of Electric Power [Line Items]
Purchase Power Agreement Expiration (year)		2032
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity		$ 69.5	$ 69.5	$ 72.7
Estimated Future Payments Under PPAs [Abstract]
2016		44.5
2017		24.3
2018		19.2
2019		10.3
2020		1.5
Thereafter		9.5
Total		109.3
Energy
Estimated Future Payments Under PPAs [Abstract]
2016	[1]	25.3
2017	[1]	4.4
2018	[1]	0.0
2019	[1]	0.0
2020	[1]	0.0
Thereafter	[1]	0.0
Total	[1]	$ 29.7

[1] Excludes contingent energy payments for renewable energy PPAs

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Commitments and Contingencies, Leases (Details) $ in Millions		12 Months Ended
		Dec. 31, 2015 USD ($) Lease	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Capital Leases [Abstract]
Number of leases qualifying as capital leases | Lease		3
Amortization expense under capital lease assets		$ 8.2	$ 7.2	$ 6.3
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease		221.2	221.2
Accumulated depreciation		(57.2)	(49.0)
Total property held under capital leases, net		$ 164.0	172.2
Operating Leased Assets [Line Items]
Operating Lease Purchase Power Agreement Expiration (years)		2032
Operating Leases, Future Minimum Payments Due [Abstract]
2016		$ 114.2
2017		103.6
2018		103.4
2019		104.3
2020		105.1
Thereafter		619.2
Capital Leases, Future Minimum Payments Due [Abstract]
2016		29.3
2017		25.7
2018		25.3
2019		25.1
2020		24.9
Thereafter		486.5
Total minimum obligation		616.8
Interest component of obligation		(452.8)
Present value of minimum obligation		$ 164.0
WYCO Totem Gas Storage Facilities
Capital Leases [Abstract]
Ownership interest in joint venture (in hundredths)		50.00%
Capital lease obligations		$ 132.9	138.9
Gas Storage Facilities
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease		200.5	200.5
Gas Pipeline
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease		20.7	20.7
Office Space and Other Equipment
Operating Leases [Abstract]
Total expenses under operating lease obligations		130.5	126.2	96.6
Operating Leases, Future Minimum Payments Due [Abstract]
2016		12.0
2017		7.8
2018		7.4
2019		7.4
2020		7.4
Thereafter		39.5
Purchased Power Agreements
Operating Leases [Abstract]
Payments for capacity for PPAs under operating lease obligations		113.5	$ 110.1	$ 79.6
Operating Leases, Future Minimum Payments Due [Abstract]
2016	[1],[2]	102.2
2017	[1],[2]	95.8
2018	[1],[2]	96.0
2019	[1],[2]	96.9
2020	[1],[2]	97.7
Thereafter	[1],[2]	$ 579.7

[1] Amounts do not include PPAs accounted for as executory contracts.

[2] PPA operating leases contractually expire through 2032.

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Commitments and Contingencies, Variable Interest Entities (Details) - MW	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Purchased Power Agreements (PPAs) [Abstract]
VIE Purchase Power Agreement Expiration (year)	2032
Independent Power Producing Entities
Purchased Power Agreements (PPAs) [Abstract]
Generating capacity (in MW)	1,802	1,802

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Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) Site	Oct. 30, 2015 Period	Dec. 31, 2014 USD ($)
Regional Haze Rules
Environmental Requirements [Abstract]
Amount spent on installation of emission controls	$ 75.2
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of phases under a consent decree which the EPA is requiring states to evaluate areas for attainment	3
Number of months in which the state would have to submit an implementation plan for the respective nonattaiment areas	18 months
Number of years for the state to achieve the designated attainment standard	5 years
National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of hours measured for standard | Period		8
Current level of air quality concentrations (in parts per billion)		75
Proposed level of air quality concentrations (in parts per billion)		70
Minimum | Capital Commitments | Federal Clean Water Act Effluent Limitations Guidelines
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation	$ 9.0
Maximum | Capital Commitments | Federal Clean Water Act Effluent Limitations Guidelines
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation	$ 21.0
Other MGP Sites
Site Contingency [Line Items]
Number of identified MGP sites under current investigation and/or remediation | Site	2
Liability for estimated cost of remediating sites	$ 1.7		$ 1.8

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Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 225,296	[1]	$ 60,398
Liabilities recognized	0		21,864
Liabilities settled	0		0
Accretion	9,575		3,701
Cash Flow Revisions	5,637	[2]	139,333	[3]
Ending balance	240,508	[4]	225,296	[1]
Electric Plant Steam and Other Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	36,856	[1]	23,914
Liabilities recognized	0		747
Liabilities settled	0		0
Accretion	1,820		1,597
Cash Flow Revisions	0	[2]	10,598	[3]
Ending balance	38,676	[4]	36,856	[1]
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	61,885	[1]	29,234
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	2,769		1,897
Cash Flow Revisions	6,113	[2]	30,754	[3]
Ending balance	70,767	[4]	61,885	[1]
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	2,095	[1]	2,953
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	18		22
Cash Flow Revisions	(121)	[2]	(880)	[3]
Ending balance	1,992	[4]	2,095	[1]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,182	[1]	1,176
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	47		43
Cash Flow Revisions	(99)	[2]	(37)	[3]
Ending balance	1,130	[4]	1,182	[1]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,150	[1]	1,017
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	46		41
Cash Flow Revisions	(142)	[2]	92	[3]
Ending balance	1,054	[4]	1,150	[1]
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	117,474	[1]	788
Liabilities recognized	0		18,252
Liabilities settled	0		0
Accretion	4,694		50
Cash Flow Revisions	0	[2]	98,384	[3]
Ending balance	122,168	[4]	117,474	[1]
Natural Gas Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	3,886	[1]	575
Liabilities recognized	0		2,865
Liabilities settled	0		0
Accretion	153		24
Cash Flow Revisions	(114)	[2]	422	[3]
Ending balance	3,925	[4]	3,886	[1]
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	768	[1]	741
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	28		27
Cash Flow Revisions	0	[2]	0	[3]
Ending balance	$ 796	[4]	$ 768	[1]

[1] There were no ARO liabilities settled during the year ended Dec. 31, 2014.

[2] In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above.

[3] In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas transmission and distribution.

[4] There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

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Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 364	$ 366

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Commitments and Contingencies, Legal Contingencies (Details) - Pacific Northwest FERC Refund Proceeding [Member]	12 Months Ended
	Dec. 31, 2015 USD ($) Factor
Legal Contingencies [Abstract]
Estimated City of Seattle's claim for refunds not including interest	$ 28,000,000
Number of factors considered in assessment | Factor	2
Accrual for legal contingency	$ 0
PSCo [Member] | Maximum
Legal Contingencies [Abstract]
Amount of Sales Claimed as Subject to Refund	50,000,000
PSCo [Member] | Minimum
Legal Contingencies [Abstract]
Amount of Sales Claimed as Subject to Refund	$ 34,000,000

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Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 92,072	$ 120,120
Regulatory Asset, Noncurrent		906,275	903,973
Past expenditures not currently earning a return		$ 54,000	104,000
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current	[1]	$ 29,260	32,195
Regulatory Asset, Noncurrent	[1]	497,973	500,889
Non Qualified Pension Plan
Regulatory Assets [Line Items]
Regulatory Asset, Current		400	400
Regulatory Asset		$ 4,400	4,500
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 144,953	141,214
Contract Valuation Adjustments
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related contract
Regulatory Asset, Current	[2]	$ 9,376	8,901
Regulatory Asset, Noncurrent	[2]	$ 9,526	12,999
Depreciation Differences
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		One to sixteen years
Regulatory Asset, Current		$ 14,221	10,700
Regulatory Asset, Noncurrent		$ 99,835	104,743
Net AROs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current	[3]	$ 0	0
Regulatory Asset, Noncurrent	[3]	$ 62,948	46,213
Conservation Programs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		One to five years
Regulatory Asset, Current	[4]	$ 8,466	10,198
Regulatory Asset, Noncurrent	[4]	$ 6,947	10,906
Gas Pipeline Inspection Costs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Less than one year
Regulatory Asset, Current		$ 3,611	5,416
Regulatory Asset, Noncurrent		$ 0	3,611
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related contract
Regulatory Asset, Current		$ 1,319	858
Regulatory Asset, Noncurrent		$ 29,143	29,596
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related debt
Regulatory Asset, Current		$ 1,421	1,426
Regulatory Asset, Noncurrent		$ 6,957	8,378
Recoverable Purchased Natural Gas and Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Less than one year
Regulatory Asset, Current		$ 408	18,410
Regulatory Asset, Noncurrent		$ 0	0
Property Tax
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		One to six years
Regulatory Asset, Current		$ 21,558	28,024
Regulatory Asset, Noncurrent		$ 14,428	31,429
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 2,432	3,992
Regulatory Asset, Noncurrent		$ 33,565	$ 13,995

[1] Includes $4.4 million and $4.5 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2015 and 2014, 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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Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 152,823	$ 134,459
Regulatory Liability, Noncurrent		471,421	464,421
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		$ 364,291	366,359
Regulatory Noncurrent Liability, Amortization Period		Plant lives
Deferred Electric, Gas, and Steam Production Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 66,696	24,035
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		$ 20,515	22,225
Regulatory Noncurrent Liability, Amortization Period		Various
Deferred Income Tax Adjustment
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0	0
Regulatory Liability, Noncurrent		$ 16,891	18,672
Regulatory Noncurrent Liability, Amortization Period		Various
Conservation Programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	$ 33,460	32,226
Regulatory Liability, Noncurrent	[2]	$ 0	0
Regulatory Noncurrent Liability, Amortization Period		Less than one year
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 3,311	3,308
Regulatory Liability, Noncurrent		$ 40,988	10,376
Regulatory Noncurrent Liability, Amortization Period		Various
Low Income Discount Program
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 1,393	1,680
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		$ 0	316
Regulatory Liability, Noncurrent		$ 0	4
Regulatory Noncurrent Liability, Amortization Period		One to three years
PSCo Earnings Test
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 42,868	57,127
Regulatory Liability, Noncurrent		$ 9,472	42,819
Regulatory Noncurrent Liability, Amortization Period		One to two years
Gas Pipeline Inspection Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 1,140	13,970
Regulatory Liability, Noncurrent		$ 4,273	642
Regulatory Noncurrent Liability, Amortization Period		One to two years
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 3,955	1,797
Regulatory Liability, Noncurrent		$ 14,991	3,324
Regulatory Noncurrent Liability, Amortization Period		Various
Other Current Liabilities [Member]
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		$ 9,100	$ 4,400

[1] Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current liabilities.

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

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Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period		$ (23,878)
Accumulated other comprehensive income (loss) at end of period		(23,836)	$ (23,878)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses		761,901	751,786	$ 762,322
Total, pre-tax		(745,242)	(698,779)	(704,123)
Income tax expense (benefit)		278,440	243,591	250,740
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period		(23,878)	(23,338)
Other comprehensive income (loss) before reclassifications		(30)	(72)
(Gains) losses reclassified from net accumulated other comprehensive loss		72	(468)
Net current period other comprehensive income (loss)		42	(540)
Accumulated other comprehensive income (loss) at end of period		(23,836)	(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		111	(755)
Income tax expense (benefit)		(39)	287
Total, net of tax		72	(468)
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[1]	54	(730)
Gains and Losses on Cash Flow Hedges | Vehicle Fuel Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	[2]	$ 57	$ (25)

[1] Included in interest charges.

[2] Included in O&M expenses

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Segments and Related Information (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Intercompany Revenue										$ 13,000	$ 14,000	$ 13,000
Operating revenues		$ 1,030,838	$ 1,044,704	$ 952,521	$ 1,135,450	$ 1,136,791	$ 1,049,111	$ 993,704	$ 1,203,543	4,163,513	4,383,149	4,202,628
Depreciation and amortization										411,667	379,202	360,417
Total interest charges and financing costs										171,908	154,640	160,945
Income tax expense (benefit)										278,440	243,591	250,740
Net income (loss)		$ 84,255	$ 173,081	$ 98,500	$ 110,966	$ 92,834	$ 154,159	$ 89,792	$ 118,403	466,802	455,188	453,383
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues										3,115,558	3,126,276	3,081,473
Depreciation and amortization										311,122	285,968	280,972
Total interest charges and financing costs										136,397	124,118	129,787
Income tax expense (benefit)										234,873	208,095	220,356
Net income (loss)										391,257	349,793	368,586
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues										1,006,733	1,215,504	1,080,813
Depreciation and amortization										96,384	89,186	75,510
Total interest charges and financing costs										34,935	29,987	30,604
Income tax expense (benefit)										44,192	50,874	42,294
Net income (loss)										74,267	84,324	69,682
All Other
Segment Reporting Information [Line Items]
Operating revenues										41,590	41,888	40,754
Depreciation and amortization										4,161	4,048	3,935
Total interest charges and financing costs										576	535	554
Income tax expense (benefit)										(625)	(15,378)	(11,910)
Net income (loss)										1,278	21,071	15,115
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	[1]									4,163,513	4,383,149	4,202,628
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	[1]									3,115,257	3,125,937	3,081,171
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	[1]									1,006,666	1,215,324	1,080,703
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	[1]									41,590	41,888	40,754
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues										(368)	(519)	(412)
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										301	339	302
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues										67	180	110
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues										$ 0	$ 0	$ 0

[1] Operating revenues include $13 million, $14 million and $13 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013, respectively. See Note 16 for further discussion of related party transactions by reportable segment.

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Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues
Electric	$ 8,632	$ 9,614	$ 8,136
Other	4,441	4,441	4,441
Operating expenses
Purchased power	0	23	1,331
Other operating expenses - paid to Xcel Energy Services Inc.	414,620	454,250	375,766
Interest expense	211	158	132
Interest income	45	61	$ 273
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	4,909	50,842
Accounts payable	76,643	46,736
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	4,419	0
Accounts payable	0	6,706
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	71	22
Accounts payable	0	0
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	414	5,803
Accounts payable	0	0
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	5	45,017
Accounts payable	$ 76,643	$ 40,030

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Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 1,030,838	$ 1,044,704	$ 952,521	$ 1,135,450	$ 1,136,791	$ 1,049,111	$ 993,704	$ 1,203,543	$ 4,163,513	$ 4,383,149	$ 4,202,628
Operating income	173,951	315,174	195,176	215,400	169,423	261,073	163,437	208,437	899,701	802,370	828,759
Net income	$ 84,255	$ 173,081	$ 98,500	$ 110,966	$ 92,834	$ 154,159	$ 89,792	$ 118,403	$ 466,802	$ 455,188	$ 453,383

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Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 23,122	$ 22,505	$ 21,918
Charged to costs and expenses		13,052	17,005	16,784
Charged to other accounts	[1]	5,175	6,240	7,005
Deductions from reserves	[2]	21,227	22,628	23,202
Balance at Dec. 31		$ 20,122	$ 23,122	$ 22,505

[1] Recovery of amounts previously written off.

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