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, 2016

or

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

Commission File Number: 001-3280

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

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

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. 24, 2017, 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 2017 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2017. 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).

TABLE OF CONTENTS

Index

PART I
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	8
Fuel Sources	8
Renewable Energy Sources	9
Wholesale Commodity Marketing Operations	10
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	15
ENVIRONMENTAL MATTERS	15
EMPLOYEES	15
Item 1A — Risk Factors	15
Item 1B — Unresolved Staff Comments	25
Item 2 — Properties	26
Item 3 — Legal Proceedings	27
Item 4 — Mine Safety Disclosures	27
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6 — Selected Financial Data	27
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	30
Item 8 — Financial Statements and Supplementary Data	32
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
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
PHMSA	Pipeline and Hazardous Materials Safety Administration
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
C&I	Commercial and Industrial
CAA	Clean Air Act
CACJA	Clean Air Clean Jobs Act
CO2	Carbon dioxide
CPCN	Certificate of public convenience and necessity

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CPP	Clean Power Plan
CWIP	Construction work in progress
ERCOT	Electric Reliability Council of Texas
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
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
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.
NAV	Net asset value
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
R&E	Research and experimentation
REC	Renewable energy credit
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
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 14 percent of its total KWh sold in 2016.  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 2016.  Although PSCo’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large C&I electric sales include the following industries:  fabricated metal products, communications and health services.  For small C&I customers, significant electric retail sales include the following industries:  real estate and dining establishments.  Generally, PSCo’s earnings contribute approximately 35 percent to 45 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.

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

• PCCA — Recovers purchased capacity payments.

• 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.

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

• 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 — Premium service for customers who choose to pay an additional charge for renewable resources.

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

• 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.

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.

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Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2017, assuming normal weather conditions, is as follows:

	System Peak Demand (in MW)
	2014	2015	2016	2017 Forecast
PSCo	6,152	6,284	6,585	6,439

The peak demand for PSCo’s system typically occurs in the summer. The 2016 system peak demand for PSCo occurred on Aug. 3, 2016. The 2016 system peak demand was higher due to Comanche Unit 3 not running at full capacity, which increased PSCo’s system load for the backup power provided by PSCo to the joint owners. The forecast of 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 capacity charge and an energy charge for 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.

Rush Creek Wind Ownership Proposal — In 2016, PSCo filed an application for a CPCN to build, own and operate a 600 MW wind generation facility at Rush Creek for a cost of approximately $1 billion, including transmission investment.

In 2016, the CPUC approved a settlement between PSCo and various parties and granted a CPCN, which allows PSCo to commence the project on a timely basis and capture the full PTC benefit for customers.

Key terms of the settlement are listed below:

• The Rush Creek project satisfies the reasonable cost standard and is in the public interest;

• The project should be placed in service by Oct. 31, 2018;

• The useful life of the project should be set at 25 years;

• A hard cost-cap on the $1.096 billion investment (which includes the capital investment and AFUDC); 

• A capital cost sharing mechanism for every $10 million below the cost-cap, with 82.5 percent retained by customers and 17.5 percent retained by PSCo on a net present value basis over the life of the project;

• Amounts retained by PSCo under the capital cost sharing mechanism as well as overall facility revenue requirements may each be reduced for lower than projected long term generating output (i.e., higher degradation);

• The Pawnee-Daniels transmission line (estimated project cost of $178 million) should be accelerated and operations are expected to begin by October 2019; and

• PSCo committed to develop a rate for third-party access to available capacity in the Rush Creek transmission line to be filed at the FERC.

Colorado 2016 ERP — In May 2016, PSCo filed its 2016 ERP which identified approximately 600 MW of additional resource needs by the summer of 2023; the level of resource need is driven by load growth, retiring generation facilities, expiring purchased power contracts and the impacts of customer-facing programs. In its initial filing, PSCo proposed a competitive acquisition process in which all generation resources, except coal-fired generation, could compete. PSCo has expressed an interest in owning incremental generation through self-build proposals, purchase of existing assets some of which are currently subject to PPAs or through build-own-transfer projects. In February 2017, the CPUC held hearings regarding PSCo’s proposal and an initial decision is anticipated by March 2017. The actual range of need to be filled in the competitive acquisition process will be determined once a final decision is received from the CPUC and prior to the beginning of the competitive acquisition phase of the ERP process.

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Brush to Castle Pines 345 KV Transmission Line — In 2015, the CPUC granted a CPCN to construct a new 345 KV transmission line originating from Pawnee generating station, near Brush, CO to the Daniels Park substation, near Castle Pines, CO to be placed in service by May 2022. The estimated project cost is $178.3 million. The CPUC granted the parties’ requests for consolidation with the Rush Creek project and approved for construction to begin in the first half of 2017.

PSCo Global Settlement Agreement — In August 2016, PSCo and various intervenors entered into a global settlement agreement regarding three pending filings with the CPUC, including the Phase II electric rate case (which is related to the rate design portion of the 2015 Electric rate case), the Renewable*Connect^® proposal and the 2017 Renewable Energy Plan. Key terms of the agreement include that participating customers in the proposed Renewable*Connect program would pay ordinary tariff electric rates in addition to a voluntary tariff solar charge, and receive bill credits related to avoided cost savings for a new 50 MW solar resource. It was also agreed that PSCo’s 2017 Renewable Energy Plan would include 2017 to 2019 acquisition of a total of 225 MW of renewable energy from sources including rooftop solar, solar gardens and recycled energy.

In December 2016, the CPUC approved the global settlement agreement. In January 2017, PSCo began implementing the terms of the settlement.

Joint Dispatch Agreement (JDA) — In February 2016, the FERC approved a JDA between PSCo, Black Hills/Colorado Electric Utility Company, LP and Platte River Power Authority. Through the JDA, energy is dispatched to economically serve the combined electric customer loads of the three systems. In circumstances where PSCo is the lowest cost producer, it will sell its excess generation to other JDA counterparties. The agreement results in a reduction in total energy costs for the parties, of which approximately $1.4 million would be allocated to PSCo’s customers. As part of the agreement, PSCo will earn a management fee to administer the JDA. In January 2017, the CPUC approved the JDA.

Advanced Grid Intelligence and Security —In August 2016, PSCo filed a request with the CPUC to approve a CPCN for implementation of its advanced grid initiative. The project incorporates installing advanced meters, implementing a combination of hardware and software applications to allow the distribution system to operate at a lower voltage (integrated volt-var optimization) and installing necessary communications infrastructure to implement this hardware. These major projects are expected to improve customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures. The estimated capital investment for the project is approximately $500 million. PSCo anticipates a CPUC decision by mid-2017. If approval is received, the project is expected to be completed by 2021.

Decoupling Filing — In July 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism for a five-year period, effective Jan. 1, 2017.  The proposed decoupling adjustment would allow PSCo to adjust annual revenues based on changes in weather normalized average use per customer for the residential and small C&I classes.  The proposed decoupling mechanism is symmetric and may result in potential refunds to customers if there were an increase in average use per customer. PSCo did not request that revenue be adjusted as a result of weather related sales fluctuations.

In January 2017, the CPUC Staff (Staff) and various intervenors, including the Office of Consumer Counsel (OCC), filed direct testimony. 

• The Staff recommended a portion of PSCo’s request be approved and suggested the CPUC should lower PSCo’s ROE by 30 basis points to account for lower risk associated with annual revenues, if the full proposal were approved;

• The OCC opposed PSCo’s decoupling request; and

• Other intervening parties generally supported PSCo’s proposal, but recommended various modifications, such as the use of actual sales data instead of weather-normalized sales.

A CPUC decision is expected in April 2017.

Boulder, Colo. Municipalization — In 2011, a ballot measure was passed which authorized the formation and operation of a municipal utility and the issuance of enterprise revenue bonds. In 2014, the City of Boulder (Boulder) City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature because costs and system separation plans were not final, but the case was dismissed. PSCo appealed this decision and in September 2016, the Colorado Court of Appeals preserved PSCo’s ability to challenge the utility while vacating the lower court’s decision.

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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. In January 2015, the Boulder District Court affirmed the CPUC decision. The Boulder District Court also dismissed a condemnation action that Boulder had filed. The CPUC must complete the separation plan proceeding before Boulder may refile a condemnation proceeding.

In July 2015, Boulder filed an application with the CPUC requesting approval of its proposed separation plan. In August 2015, PSCo filed a motion to dismiss Boulder’s separation proposal, arguing Boulder’s request was not permissible under Colorado law. In December 2015, the CPUC granted the motion to dismiss the application in part, holding that Boulder had no right to acquire PSCo facilities used exclusively to serve customers located outside Boulder city limits. Other portions of Boulder’s application were not dismissed, but were stayed until Boulder supplemented its application. Boulder filed its amended application in September 2016.

In February 2017, PSCo and other intervenors filed answer testimony which addressed several legal issues posed by the CPUC. Overall, PSCo believes that Boulder’s plan is not consistent with and cannot be effectively administered under Colorado law and that from a reliability perspective it is an inappropriate way to separate the two distribution systems and poses significant risks to PSCo and its remaining customers. The remaining key dates in the procedural schedule are as follows:

• Rebuttal testimony — March 30, 2017;

• Hearings — April 26 through May 5, 2017;

• Statements of position — May 17, 2017; and

• Final decision — June 15, 2017.

Depreciation and Amortization Proceeding — In April 2016, PSCo filed for approval of depreciation rates and amortization schedules for its electric and common plant. In January 2017, the CPUC approved a comprehensive settlement agreement. The new depreciation and amortization rates are expected to be implemented in conjunction with PSCo’s next rate case or through a separate proceeding in 2018, with an expected annual increase of approximately $33 million.

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 was in compliance with the RES as of Dec. 31, 2016.

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
2016	$	1.75	72	%	$	3.79	28	%	$	2.33
2015	1.75		75		3.89		25		2.29
2014	1.82		75		5.32		25		2.68

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

Fuel Sources

Coal— PSCo normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2016 and 2015 were approximately 36 and 49 days of usage, respectively. At Dec. 31, 2016, stockpile reductions in preparation for unit retirements at the Cherokee and Valmont stations in 2017 resulted in coal inventories being slightly below optimal levels. PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2016 and 2015, PSCo’s coal requirements for existing plants were approximately 9.9 million tons and 10.5 million tons, respectively. The estimated coal requirements for 2017 are approximately 10.0 million tons. The increase is primarily due to higher expected natural gas prices in 2017.

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PSCo has contracted for coal supply to provide 84 percent of its estimated coal requirements in 2017, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 80 percent of requirements for the first year, 50 percent of requirements in year two, and 25 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 its coal requirements in 2017 and 2018. 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, 2016, PSCo’s commitments related to gas supply contracts, which expire in various years from 2017 through 2023, were approximately $654 million and commitments related to gas transportation and storage contracts, which expire in various years from 2017 through 2060, were approximately $573 million.

• At Dec. 31, 2015, PSCo’s commitments related to gas supply contracts were approximately $750 million and commitments related to gas transportation and storage contracts were approximately $684 million.

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

Renewable Energy Sources

PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2016, PSCo was in compliance with mandated RPS, which requires generation from renewable resources of 20.0 percent of electric retail sales.

• Renewable energy comprised 28.3 percent and 22.0 percent of PSCo’s total energy for 2016 and 2015, respectively;

• Wind energy comprised 23.7 percent and 19.4 percent of the total energy for 2016 and 2015, respectively; and

• Hydroelectric, biomass and solar power comprised approximately 4.6 percent and 2.6 percent of the total energy for 2016 and 2015.

PSCo also offers customer-focused renewable energy initiatives. Windsource^® allows customers to purchase a portion or all of their electricity from renewable sources. In 2016, the number of customers utilizing Windsource increased to approximately 46,000 from 45,000 in 2015.

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 32,500 PV systems with approximately 276 MW of aggregate capacity and over 29,500 PV systems with approximately 258 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2016 and 2015, respectively. Additionally, 25 community solar gardens with 18.1 MW of capacity and 24 gardens with 16.6 MW of capacity have been completed in Colorado as of Dec. 31, 2016 and 2015, respectively.

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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 of wind energy on its system at the end of 2016 and 2015. 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 in 2016 and 2015. 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 2016 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. PSCo also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved JOA. See Item 7 for further discussion.

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.

Status of FERC Commissioners — The FERC is comprised of five commissioners appointed by the President and subject to confirmation by the Senate. There are today only two sitting commissioners.  It is uncertain when the President will appoint new commissioners to the open seats or when those appointments may be confirmed.  Without three sitting commissioners, the FERC will not have a quorum to act on contested matters. The lack of a quorum could affect the timing of FERC decisions on proposed rules or pending, newly submitted and future filings involving, among other things, contested electric rate matters and CPCNs for construction of interstate natural gas pipeline facilities.

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. PSCo applied the requirements to high and medium impact assets by the July 1, 2016 deadline. Requirements must be applied to low impact assets through a staggered implementation beginning April 1, 2017 through September 2018. PSCo is currently in the process of implementing initiatives to meet the compliance deadline. The additional cost for compliance is anticipated to be recoverable through rates.

NERC Physical Security Requirements — In 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 developed physical security plans in accordance with the requirements of the standard. The additional cost for compliance is anticipated to be recoverable through rates.

Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, PSCo filed changes to its transmission

formula rate and production formula rate to comply with IRS guidance regarding how ADIT must be reflected in formula rates using

future test years and a true-up. The filings were intended to ensure that PSCo is in compliance with IRS rules and may continue to use

accelerated tax depreciation. PSCo requested a Jan. 1, 2016 effective date.

In April 2016, the FERC accepted PSCo’s ADIT formula rate changes, effective Jan. 1, 2016, subject to a compliance filing. In August 2016, the FERC approved PSCo’s compliance filing. PSCo believes its wholesale formula rates are in compliance with the IRS ADIT rules.

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Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC —In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a QF must be a successful bidder in a PSCo resource acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA. If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. FERC action is pending.

Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2016			2015			2014
Electric sales (Millions of KWh)
Residential	9,272			9,112			9,009
Large commercial and industrial	6,371			6,596			6,712
Small commercial and industrial	12,890			12,750			12,709
Public authorities and other	268			242			241
Total retail	28,801			28,700			28,671
Sales for resale	4,672			3,581			3,664
Total energy sold	33,473			32,281			32,335
Number of customers at end of period
Residential	1,235,378			1,218,662			1,202,621
Large commercial and industrial	337			337			334
Small commercial and industrial	159,299			158,086			156,809
Public authorities and other	54,048			53,944			53,824
Total retail	1,449,062			1,431,029			1,413,588
Wholesale	34			26			23
Total customers	1,449,096			1,431,055			1,413,611
Electric revenues (Thousands of Dollars)
Residential	$	1,063,526		$	1,060,626		$	1,081,092
Large commercial and industrial	414,797			433,061			462,449
Small commercial and industrial	1,204,881			1,220,064			1,267,023
Public authorities and other	54,070			52,783			54,555
Total retail	2,737,274			2,766,534			2,865,119
Wholesale	152,375			180,716			211,241
Other electric revenues	159,703			168,007			49,577
Total electric revenues	$	3,049,352		$	3,115,257		$	3,125,937
KWh sales per retail customer	19,876			20,055			20,282
Revenue per retail customer	$	1,889		$	1,933		$	2,027
Residential revenue per KWh	11.47		¢	11.64		¢	12.00		¢
Large commercial and industrial revenue per KWh	6.51			6.57			6.89
Small commercial and industrial revenue per KWh	9.35			9.57			9.97
Total retail revenue per KWh	9.50			9.64			9.99
Wholesale revenue per KWh	3.26			5.05			5.77

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Energy Source Statistics

	Year Ended Dec. 31
	2016			2015			2014
	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	15,895	47	%	18,601	54	%	18,274	53	%
Natural Gas	8,632	25		7,948	23		8,601	25
Wind (a)	8,106	24		6,699	19		6,472	19
Hydroelectric	1,179	3		662	2		617	2
Other (b)	393	1		705	2		294	1
Total	34,205	100	%	34,615	100	%	34,258	100	%
Owned generation	22,753	67	%	22,981	66	%	23,023	67	%
Purchased generation	11,452	33		11,634	34		11,235	33
Total	34,205	100	%	34,615	100	%	34,258	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 396, 245 and 197 million net KWh for 2016, 2015, and 2014, 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 2016, average annual sales to the typical PSCo residential customer declined 16 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

Protecting our Infrastructure of Pipelines and Enhancing Safety Act (PIPES) Act —The PIPES Act, signed into law in June 2016, requires the DOT PHMSA to issue regulations on the construction and operation of the nation’s underground gas storage fields. The act also grants PHMSA emergency order authority for pipeline operators, which would require operators to make immediate changes to assets or operations. The act also directs PHMSA to continue work on a variety of mandates from the 2012 Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act), many of which have not been completed.

PHMSA issued interim final rules for underground storage operators in December 2016. PSCo operates three underground storage fields in Colorado and is developing a plan to meet the storage rules. PSCo does not expect these changes to have a material impact on costs or operating reliability.

Pipeline Safety Act — The 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 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.

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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. PSCo is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. PSCo cannot predict the ultimate impact the Pipeline Safety Act will have on its costs, operations or financial results. PSCo can generally recover costs to comply with the transmission and distribution integrity management programs through the PSIA rider.

Public Utility Regulation

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

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

• 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 — Recovers costs of DSM and performance initiatives to achieve various energy savings goals.

• PSIA — Recovers costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. The rider has been 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 1,932,070 MMBtu, which occurred on Dec. 17, 2016 and 1,633,493 MMBtu, which occurred on March 4, 2015.

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 1,818,151 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.

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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:

2016	$	3.27
2015	3.92
2014	4.91

The cost of natural gas in 2016 decreased due to lower wholesale commodity prices.

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, 2016, PSCo was committed to approximately $884 million in such obligations under these contracts, which expire in various years from 2017 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 2016, 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
	2016		2015		2014
Natural gas deliveries (Thousands of MMBtu)
Residential	90,941		92,001		99,127
Commercial and industrial	38,093		38,405		40,438
Total retail	129,034		130,406		139,565
Transportation and other	117,462		108,860		108,006
Total deliveries	246,496		239,266		247,571
Number of customers at end of period
Residential	1,269,338		1,254,056		1,240,674
Commercial and industrial	100,718		100,389		100,238
Total retail	1,370,056		1,354,445		1,340,912
Transportation and other	7,261		6,936		6,547
Total customers	1,377,317		1,361,381		1,347,459
Natural gas revenues (Thousands of Dollars)
Residential	$	611,804	$	678,909	$	824,633
Commercial and industrial	228,103		257,287		313,821
Total retail	839,907		936,196		1,138,454
Transportation and other	117,814		70,470		76,870
Total natural gas revenues	$	957,721	$	1,006,666	$	1,215,324
MMBtu sales per retail customer	94.18		96.28		104.08
Revenue per retail customer	$	613	$	691	$	849
Residential revenue per MMBtu	6.73		7.38		8.32
Commercial and industrial revenue per MMBtu	5.99		6.70		7.76
Transportation and other revenue per MMBtu	1.00		0.65		0.71

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GENERAL

Seasonality

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

Competition

PSCo is a vertically integrated utility, subject to traditional cost-of-service regulation. However, PSCo is subject to different public policies that promote competition and the development of energy markets. PSCo’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with 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 PSCo’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. PSCo believes, based on prior state commission practice, it would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2016, PSCo had 2,575 full-time employees, of which 1,984 were covered under collective-bargaining agreements. See Note 8 to the consolidated financial statements for further discussion.

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Item 1A — Risk Factors

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

Oversight of Risk and Related Processes

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

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. The business planning process also 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, PSCo has developed a robust compliance program and promotes 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, PSCo manages and further mitigates 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 of Directors and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of Directors with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board of Directors in presentations and communications over the course of the year.

The Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of PSCo. First, the Board of Directors regularly reviews management’s key risk assessment and analyzes areas of existing and future risks and opportunities. In addition, the Board of Directors 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 appropriate committee. 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 of Directors’ 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 of Directors for consideration where deemed appropriate to ensure broad Board of Directors’ understanding of the nature of the risk. Finally, the Board of Directors conducts an annual strategy session where PSCo’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, 2016, 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 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. We are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. 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 while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. 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.

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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.

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, MISO and ERCOT, 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.

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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 PSCo could trigger settlement accounting and could require PSCo 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.

Changes in federal tax law may significantly impact our business.

There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping rates lower than without such provisions. Examples of these include the use of accelerated and bonus depreciation for most of our capital investments, PTCs for wind energy, investment tax credits for solar energy and research and development tax credits and deductions. Changes to current federal tax law have the ability to benefit or adversely affect our earnings and our customer costs. Significant changes in corporate tax rates could result in the impairment of deferred tax assets that are established based on existing law. Changes to the value of various tax credits could change the economics of resources and our resource selections. While regulation allows us to incorporate changes in tax law into the rate-setting process, there could be timing delays before realization of the changes.

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.

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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, including community solar gardens and customer-sited solar, shifts away from coal generation to decrease CO₂ emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Over time, customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if PSCo is not able to fully recover the costs and investments. These changes also 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. In addition, we are also subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources during the planning period could jeopardize long-term operations of our facilities or make them uneconomic to operate.

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 CO₂ emissions profile. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Early plant retirements that may result from these changes 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 and electric 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. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and widespread outages which could cause substantial financial losses. In addition, these natural gas and electric risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. We maintain insurance against some, but not all, of these risks and losses.

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

Additionally, for natural gas 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.

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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, 2016, Xcel Energy Inc. and its utility subsidiaries had approximately $14.2 billion of long-term debt and $0.6 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, 2016, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $18.8 million and exposure of $0.1 million. Xcel Energy also had additional guarantees of $43.0 million at Dec. 31, 2016 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 2016, 2015 and 2014 we paid $336.6 million, $330.8 million and $433.8 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs.  This could adversely affect our liquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more 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.

In 2015, the 21^st Conference of the Parties to the United Nations Framework Convention on Climate Change 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. If implemented, the Paris Agreement could result in future additional GHG reductions in the United States.

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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 EPA has proposed the CPP, which would regulate GHGs from power plants by mandating state plans to achieve state-specific emission reduction goals. The legality of the CPP has been challenged in the courts, and the Supreme Court stayed the rule while those challenges proceed. If the rule is ultimately implemented, uncertainties remain regarding implementation plans, including available opportunities to reduce costs, availability of emission trading, 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.

Some states have indicated a desire to continue to pursue climate policies even in the absence of federal mandates. All of the steps that PSCo has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put PSCo in a good position to meet federal standards under the CPP or the Paris Agreement, repeal of these policies would not impact those state-endorsed actions and plans.

Whether under state or federal programs, 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 PM, 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 $1.2 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas.  Under statute, the FERC can adjust penalties for inflation. 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. Additionally, the PHMSA, the Occupational Safety and Health Administration and other federal agencies also have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties in the event of non-compliance.  If a serious reliability or safety incident did occur, it could have a material effect on our operations or financial results.

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. We are also managing natural gas risk on our system by removing types of pipe (e.g. cast iron) with known problem tendencies and by testing transmission pipelines in high consequence areas. However, there is no guarantee our compliance programs 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, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, 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.

Our operations use third party contractors in addition to employees to perform periodic and on-going work.

We rely on third party contractors with specific qualifications to perform work both for ongoing operations and maintenance and for capital construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines for PSCo.

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 2016 Net Dependable Capability (MW)
Steam:
Cherokee-Denver, Colo., 1 Unit	Coal	1968	352	(a)
Comanche-Pueblo, Colo.
Unit 1	Coal	1973	325
Unit 2	Coal	1975	335
Unit 3	Coal	2010	500	(b)
Craig-Craig, Colo., 2 Units	Coal	1979-1980	83	(c)
Hayden-Hayden, Colo., 2 Units	Coal	1965-1976	233	(d)
Pawnee-Brush, Colo., 1 Unit	Coal	1981	505
Valmont-Boulder, Colo., 1 Unit	Coal	1964	184	(e)
Combustion Turbine:
Blue Spruce-Aurora, Colo., 2 Units	Natural Gas	2003	264
Cherokee-Denver, Colo., 3 Units	Natural Gas	2015	576
Fort St. Vrain-Platteville, Colo., 6 Units	Natural Gas	1972-2009	968
Rocky Mountain-Keenesburg, Colo., 3 Units	Natural Gas	2004	580
Various locations, 6 Units	Natural Gas	Various	171
Hydro:
Cabin Creek-Georgetown, Colo.
Pumped Storage, 2 Units	Hydro	1967	210
Various locations, 9 Units	Hydro	Various	26
		Total	5,312

^(a)  Cherokee Unit 4 will be fuel switched from coal to natural gas by Dec. 31, 2017.

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

^(c)  Based on PSCo’s ownership interest of 10 percent. Craig Unit 1 is expected to be early retired in approximately 2025.

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

^(e)  Valmont Unit 5 will be retired by Dec. 31, 2017.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2016:

Conductor Miles
345 KV	2,630
230 KV	12,890
138 KV	92
115 KV	4,929
Less than 115 KV	76,355

PSCo had 230 electric utility transmission and distribution substations at Dec. 31, 2016.

Natural gas utility mains at Dec. 31, 2016:

Miles
Transmission	2,281
Distribution	22,262

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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 2016 and 2015 were as follows:

(Thousands of Dollars)	2016		2015
First quarter	$	83,914	$	80,650
Second quarter	86,509		82,872
Third quarter	82,785		83,672
Fourth quarter	74,208		83,373

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, 2016 (including 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 of 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 $463.5 million for 2016, compared with approximately $466.8 million for 2015.  The positive impact of higher natural gas margins (primarily due to a rate increase), sales growth and a lower estimated electric earnings test refund, were more than offset by increased depreciation and interest charges.

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)	2016			2015
Electric revenues	$	3,049		$	3,115
Electric fuel and purchased power	(1,196		)	(1,247		)
Electric margin	$	1,853		$	1,868

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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)	2016 vs. 2015
Fuel and purchased power cost recovery	$	(40	)
DSM program revenues, offset by expenses	(14		)
Firm wholesale	(12		)
Trading, including REC sales	(9		)
Non-fuel riders	(5		)
Retail sales growth, excluding weather impact	15
Earnings test refunds	6
Other, net	(7		)
Total decrease in electric revenues	$	(66	)

Electric Margin

(Millions of Dollars)	2016 vs. 2015
DSM program revenues, offset by expenses	$	(14	)
Firm wholesale	(12		)
Non-fuel riders	(5		)
Retail sales growth, excluding weather impact	15
Earnings test refunds	6
Other, net	(5		)
Total decrease in electric margin	$	(15	)

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)	2016			2015
Natural gas revenues	$	958		$	1,007
Cost of natural gas sold and transported	(425		)	(502		)
Natural gas margin	$	533		$	505

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)	2016 vs. 2015
Purchased natural gas adjustment clause recovery	$	(78	)
Infrastructure and integrity riders, partially offset in O&M expenses	(9		)
Retail rate increase	32
DSM program revenues, offset by expenses	2
Other, net	4
Total decrease in natural gas revenues	$	(49	)

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Natural Gas Margin

(Millions of Dollars)	2016 vs. 2015
Retail rate increase	$	32
DSM program revenues, offset by expenses	2
Infrastructure and integrity riders, partially offset in O&M expenses	(9		)
Other, net	3
Total increase in natural gas margin	$	28

Non-Fuel Operating Expenses and Other Items

DSM Program Expenses— DSM program expenses decreased $10.5 million, or 8.2 percent, for 2016 compared with 2015.  The decrease was primarily attributable to lower electric recovery rates. Lower DSM program expenses are generally offset by lower revenues.

Depreciation and Amortization— Depreciation and amortization expense increased by approximately $31.9 million, or 7.7 percent,for 2016 compared with 2015.  The increase is primarily attributable to capital investments.

AFUDC— AFUDC increased by $5.6 million for 2016 compared with 2015.  The increase was primarily due to the expansion of transmission facilities and other capital expenditures.

Interest Charges —Interest charges increased by $4.2 million, or 2.4 percent, for 2016 compared with 2015.  The increase is primarily due to higher long-term debt levels to fund capital investments.

Income Taxes — Income tax expense decreased $4.5 million for 2016 compared with 2015.  The decrease in income tax expense was primarily due to lower pretax earnings in 2016 and increased plant-related adjustments (e.g., AFUDC-equity) in 2016.  The ETR was 37.1 percent for 2016 compared with 37.4 percent for 2015. The lower ETR in 2016 was primarily due to the adjustments referenced above.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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

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

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

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.

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Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives.  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, 2016, 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	$	(188	)	$	—	$	—	$	—	$	(188	)

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)	2016			2015
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	112		$	—
Contracts realized or settled during the period	(654		)	14
Commodity trading contract additions and changes during the period	354			98
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	(188	)	$	112

At Dec. 31, 2016, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.9 million, whereas a 10 percent decrease would increase pretax income by approximately $0.9 million. 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.

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
2016	$	0.09	$	3.00	$	0.16	$	0.38	$	0.05
2015	0.10		3.00		0.28		1.34			0.06

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, 2016, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately $1.3 million, and 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. See Note 10 to the consolidated financial statements for a discussion of PSCo’s interest rate derivatives.

31

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, 2016, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $14.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $2.2 million.  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.

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, 2016.  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, 2016.

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 immaterial Level 3 commodity derivative assets or liabilities at Dec. 31, 2016.

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.

32

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.

In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system. PSCo will initiate deployment of work management systems modules, including the conversion of existing work management systems, during 2017. PSCo does not believe this implementation has or will have an adverse effect on its internal control over financial reporting.

PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2016. 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, 2016, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ BEN FOWKE	/s/ ROBERT C. FRENZEL
Ben Fowke	Robert C. Frenzel
Chairman and Chief Executive Officer	Executive Vice President, Chief Financial Officer
Feb. 24, 2017	Feb. 24, 2017

33

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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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 24, 2017

34

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2016			2015			2014
Operating revenues
Electric	$	3,049,352		$	3,115,257		$	3,125,937
Natural gas	957,721			1,006,666			1,215,324
Steam and other	40,723			41,590			41,888
Total operating revenues	4,047,796			4,163,513			4,383,149
Operating expenses
Electric fuel and purchased power	1,196,417			1,246,666			1,405,498
Cost of natural gas sold and transported	425,410			501,824			725,754
Cost of sales — steam and other	15,872			17,788			16,831
Operating and maintenance expenses	762,416			761,901			751,786
Demand side management program expenses	118,175			128,681			139,780
Depreciation and amortization	443,555			411,667			379,202
Taxes (other than income taxes)	196,330			195,285			161,928
Total operating expenses	3,158,175			3,263,812			3,580,779
Operating income	889,621			899,701			802,370
Other income, net	3,817			2,964			4,265
Allowance for funds used during construction —  equity	18,557			14,485			46,784
Interest charges and financing costs
Interest charges — includes other financing costs of $6,289, $6,285 and $6,340, respectively	181,631			177,430			171,881
Allowance for funds used during construction — debt	(7,045		)	(5,522		)	(17,241		)
Total interest charges and financing costs	174,586			171,908			154,640
Income before income taxes	737,409			745,242			698,779
Income taxes	273,918			278,440			243,591
Net income	$	463,491		$	466,802		$	455,188

See Notes to Consolidated Financial Statements

35

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2016			2015			2014
Net income	$	463,491		$	466,802		$	455,188
Other comprehensive income (loss)
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $(138), $0, and $0	(223		)	—			—
Amortization of losses included in net periodic benefit cost, net of tax of $2, $0, and $0, respectively	3			—			—
	(220		)	—			—
Derivative instruments:
Net fair value decrease, net of tax of $0, $(20), and $(43), respectively	—			(30		)	(72		)
Reclassification of losses (gains) to net income, net of tax of $648, $39, and $(287), respectively	1,056			72			(468		)
	1,056			42			(540		)
Other comprehensive income (loss)	836			42			(540		)
Comprehensive income	$	464,327		$	466,844		$	454,648

See Notes to Consolidated Financial Statements

36

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2016			2015			2014
Operating activities
Net income	$	463,491		$	466,802		$	455,188
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	446,179			416,427			383,992
Demand side management program amortization	2,138			3,509			4,331
Deferred income taxes	222,002			277,896			227,823
Amortization of investment tax credits	(2,805		)	(2,807		)	(2,941		)
Allowance for equity funds used during construction	(18,557		)	(14,485		)	(46,784		)
Provision for bad debts	14,121			13,052			17,005
Net realized and unrealized hedging and derivative transactions	1,325			2,414			(2,578		)
Other	(388		)	2,500			—
Changes in operating assets and liabilities:
Accounts receivable	(14,227		)	8,872			(42,921		)
Accrued unbilled revenues	(20,866		)	17,837			(23,132		)
Inventories	172			33,417			(972		)
Prepayments and other	68,693			10,483			(81,715		)
Accounts payable	38,439			(40,982		)	(22,789		)
Net regulatory assets and liabilities	4,143			78,055			130,499
Other current liabilities	1,892			19,654			5,284
Pension and other employee benefit obligations	(10,627		)	(23,449		)	(38,905		)
Change in other noncurrent assets	(6,750		)	4,086			5,537
Change in other noncurrent liabilities	(22,120		)	(35,334		)	(19,130		)
Net cash provided by operating activities	1,166,255			1,237,947			947,792
Investing activities
Utility capital/construction expenditures	(1,113,800		)	(995,597		)	(1,114,338		)
Proceeds from insurance recoveries	608			—			—
Allowance for equity funds used during construction	18,557			14,485			46,784
Investments in utility money pool arrangement	(444,000		)	(196,300		)	(603,000		)
Repayments from utility money pool arrangement	444,000			212,300			659,000
Other	(1,460		)	—			—
Net cash used in investing activities	(1,096,095		)	(965,112		)	(1,011,554		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	115,000			(368,000		)	382,000
Borrowings under utility money pool arrangement	524,500			165,000			333,000
Repayments under utility money pool arrangement	(524,500		)	(165,000		)	(333,000		)
Proceeds from issuance of long-term debt	244,507			246,751			295,598
Repayments of long-term debt	(129,500		)	—			(275,000		)
Capital contributions from parent	38,755			175,210			81,498
Dividends paid to parent	(336,581		)	(330,846		)	(433,788		)
Net cash (used in) provided by financing activities	(67,819		)	(276,885		)	50,308
Net change in cash and cash equivalents	2,341			(4,050		)	(13,454		)
Cash and cash equivalents at beginning of period	3,585			7,635			21,089
Cash and cash equivalents at end of period	$	5,926		$	3,585		$	7,635
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(171,714	)	$	(165,546	)	$	(150,011	)
Cash received (paid) for income taxes, net	22,827			13,822			(91,810		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	68,870		$	106,912		$	139,616

See Notes to Consolidated Financial Statements

37

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	Dec. 31
	2016			2015
Assets
Current assets
Cash and cash equivalents	$	5,926		$	3,585
Accounts receivable, net	304,900			300,882
Accounts receivable from affiliates	9,421			4,909
Accrued unbilled revenues	297,078			276,212
Inventories	202,220			205,562
Regulatory assets	103,783			92,072
Derivative instruments	10,934			1,945
Prepaid taxes	9,124			81,162
Prepayments and other	25,435			22,698
Total current assets	968,821			989,027
Property, plant and equipment, net	12,849,799			12,172,211
Other assets
Regulatory assets	958,429			906,275
Derivative instruments	3,398			3,478
Other	25,637			18,224
Total other assets	987,464			927,977
Total assets	$	14,806,084		$	14,089,215
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	5,270		$	8,103
Short-term debt	129,000			14,000
Accounts payable	376,186			352,701
Accounts payable to affiliates	98,797			76,643
Regulatory liabilities	101,110			152,823
Taxes accrued	171,862			166,660
Accrued interest	48,619			49,698
Dividends payable to parent	74,208			83,374
Derivative instruments	6,788			8,881
Other	73,022			78,910
Total current liabilities	1,084,862			991,793
Deferred credits and other liabilities
Deferred income taxes	2,889,129			2,658,198
Deferred investment tax credits	30,661			33,466
Regulatory liabilities	512,933			471,421
Asset retirement obligations	289,563			240,508
Derivative instruments	7,828			13,020
Customer advances	162,742			198,526
Pension and employee benefit obligations	285,774			200,774
Other	62,201			63,864
Total deferred credits and other liabilities	4,240,831			3,879,777
Commitments and contingencies
Capitalization
Long-term debt	4,210,936			4,097,493
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively	—			—
Additional paid in capital	3,633,216			3,620,824
Retained earnings	1,659,239			1,523,164
Accumulated other comprehensive loss	(23,000		)	(23,836		)
Total common stockholder’s equity	5,269,455			5,120,152
Total liabilities and equity	$	14,806,084		$	14,089,215

See Notes to Consolidated Financial Statements

38

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, 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
Net income						463,491						463,491
Other comprehensive income									836			836
Common dividends declared to parent						(327,416		)				(327,416		)
Contribution of capital by parent				12,392								12,392
Balance at Dec. 31, 2016	100	$	—	$	3,633,216	$	1,659,239		$	(23,000	)	$	5,269,455

See Notes to Consolidated Financial Statements

39

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

	Dec. 31
	2016			2015
Long-Term Debt
First Mortgage Bonds, Series due:
Sept. 1, 2017, 4.375% (a)	$	—		$	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			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
June 15, 2046, 3.55%	250,000			—
Capital lease obligations, through 2060, 11.2% — 14.3%	155,927			164,031
Unamortized discount	(12,922		)	(11,340		)
Unamortized debt expense	(26,799		)	(26,595		)
Total	4,216,206			4,105,596
Less current maturities	5,270			8,103
Total long-term debt	$	4,210,936		$	4,097,493
Common Stockholder’s Equity
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively.	$	—		$	—
Additional paid-in capital	3,633,216			3,620,824
Retained earnings	1,659,239			1,523,164
Accumulated other comprehensive loss	(23,000		)	(23,836		)
Total common stockholder’s equity	$	5,269,455		$	5,120,152

^(a)  Pollution control financing.

See Notes to Consolidated Financial Statements

40

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.

41

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 as alternative revenue programs under GAAP. 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 C&I 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 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 2.6, 2.7 and 2.7 percent for the years ended Dec. 31, 2016, 2015 and 2014, 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.

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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 tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.

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

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

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

See Note 7 for further discussion of income taxes.

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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 and 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 NAVs.  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.

Reclassifications— Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation. See Note 2 for further discussion of recently adopted accounting pronouncements.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

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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 new framework for the recognition of revenue. PSCo expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs in the consolidated statements of income. PSCo has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination of whether receipts of non-refundable contributions in aid of construction should be recognized as revenues or may continue to be recorded as reductions to property, plant and equipment. Also, it is yet to be determined whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts of revenue recognized upon delivery. PSCo currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

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 No. 2016-01 on its consolidated financial statements.

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

Recently Adopted

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its consolidated financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. PSCo implemented the new guidance as required on Jan. 1, 2016, and as a result, $26.6 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a NAV methodology in the fair value hierarchy. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No. 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the consolidated 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. PSCo early adopted the new guidance in the fourth quarter of 2016 and as a result $62.7 million of current deferred income taxes were retrospectively reclassified to long-term deferred income tax liabilities on the consolidated balance sheet as of Dec. 31, 2015.

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Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. PSCo adopted the guidance in 2016, and the implementation did not have a material impact on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	324,512		$	321,004
Less allowance for bad debts	(19,612		)	(20,122		)
	$	304,900		$	300,882

(Thousands of Dollars)	Dec. 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	66,161	$	58,128
Fuel	66,429		78,586
Natural gas	69,630		68,848
	$	202,220	$	205,562

(Thousands of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	12,304,436		$	11,856,126
Natural gas plant	3,710,772			3,420,249
Common and other property	919,955			862,840
Plant to be retired (a)	31,839			38,249
Construction work in progress	484,340			408,963
Total property, plant and equipment	17,451,342			16,586,427
Less accumulated depreciation	(4,601,543		)	(4,414,216		)
	$	12,849,799		$	12,172,211

^(a)  In 2017, PSCo expects to early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired by approximately 2025.  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, 2016
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	56
Maximum amount outstanding	141
Weighted average interest rate, computed on a daily basis	0.78		%
Weighted average interest rate at period end	N/A

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(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	21			1			4
Maximum amount outstanding	141			34			97
Weighted average interest rate, computed on a daily basis	0.73		%	0.41		%	0.25		%
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, 2016
Borrowing limit	$	700
Amount outstanding at period end	129
Average amount outstanding	33
Maximum amount outstanding	151
Weighted average interest rate, computed on a daily basis	0.78		%
Weighted average interest rate at period end	0.95

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	129			14			382
Average amount outstanding	24			95			167
Maximum amount outstanding	154			449			393
Weighted average interest rate, computed on a daily basis	0.70		%	0.51		%	0.31		%
Weighted average interest rate at period end	0.95			0.60			0.65

Letters of Credit— PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2016 and 2015, there were $3 million and $4 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

Amended Credit Agreement— In June 2016, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $700 million. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions:

• The maturity extended from October 2019 to June 2021.

• The Eurodollar borrowing margin on this line of credit was reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.

• The commitment fees, calculated on the unused portion of the line of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

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PSCo has the right to request an extension of the termination date for two additional one-year periods. The 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 at both Dec. 31, 2016 and 2015. 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, 2016 and 2015.

At Dec. 31, 2016, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700	$	132	$	568

^(a)  This credit facility matures in June 2021.

^(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, 2016 and 2015.

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 2016, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046. In 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025.

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

Deferred Financing Costs— Deferred financing costs of approximately $26.8 million and $26.6 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2016 and 2015, 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, 2016:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	149,221	$	67,415	$	97	76	%
Hayden Unit 2	148,795		64,024		64		37
Hayden Common Facilities	38,230		18,951		282		53
Craig Units 1 and 2	60,318		37,570		15,730		10
Craig Common Facilities 1, 2 and 3	37,925		19,312		183		7
Comanche Unit 3	892,978		112,254		6		67
Comanche Common Facilities	24,694		1,821		636		82
Electric Transmission:
Transmission and other facilities, including substations	166,840		65,619		4,313		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	23,406		7,679		—		60
Gas Transportation Compressor	8,397		368		—		50
Total	$	1,550,804	$	395,013	$	21,311

PSCo has approximately 816 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.

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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.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the IRS commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of Dec. 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their cases to 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, following extensions, expires in December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’ proposed adjustment of the carryback claims. PSCo is not expected to accrue any income tax expense related to this adjustment.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013. Subsequent to year-end, the IRS proposed an adjustment to tax years 2012 through 2013 that may impact Xcel Energy’s NOL and tax credit carryforwards and ETR. However, Xcel Energy is continuing to evaluate the IRS’ proposal and the outcome and timing of a resolution is uncertain.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2016, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits— The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.9	$	2.4
Unrecognized tax benefit — Temporary tax positions	16.8		15.0
Total unrecognized tax benefit	$	19.7	$	17.4

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

(Millions of Dollars)	2016			2015			2014
Balance at Jan. 1	$	17.4		$	11.9		$	8.4
Additions based on tax positions related to the current year	2.7			4.5			3.7
Reductions based on tax positions related to the current year	—			(1.5		)	(0.7		)
Additions for tax positions of prior years	0.5			2.5			2.8
Reductions for tax positions of prior years	(0.9		)	—			(1.2		)
Settlements with taxing authorities	—			—			(1.1		)
Balance at Dec. 31	$	19.7		$	17.4		$	11.9

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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, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.8	)	$	(4.3	)

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

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)	2016			2015			2014
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.4	)	$	(0.2	)	$	(0.1	)
Interest expense related to unrecognized tax benefits	(0.7		)	(0.2		)	(0.1		)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(1.1	)	$	(0.4	)	$	(0.2	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2016, 2015 or 2014.

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)	2016			2015
Federal NOL carryforward	$	260		$	328
Federal tax credit carryforwards	25			24
State NOL carryforwards	684			684
State tax credit carryforwards, net of federal detriment (a)	13			13
Valuation allowances for state credit carryforwards, net of federal detriment (b)	(3		)	(1		)

^(a)  State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2016 and 2015, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $1 million as of Dec. 31, 2016 and 2015, respectively.

The federal carryforward periods expire between 2021 and 2036.  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:

	2016		2015		2014
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		3.2		2.8
Tax credits recognized, net of federal income tax expense	(0.7	)	(0.7	)	(0.8	)
Regulatory differences — utility plant items	(0.5	)	(0.3	)	(2.1	)
Change in unrecognized tax benefits (expense)	—		0.1		(0.1	)
Other, net	0.1		0.1		0.1
Effective income tax rate	37.1	%	37.4	%	34.9	%

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

(Thousands of Dollars)	2016			2015			2014
Current federal tax expense (benefit)	$	45,287		$	(1,166	)	$	9,550
Current state tax expense (benefit)	8,754			(727		)	2,611
Current change in unrecognized tax expense	680			5,244			6,548
Deferred federal tax expense	195,064			246,096			208,781
Deferred state tax expense	27,216			36,450			26,196
Deferred change in unrecognized tax benefit	(278		)	(4,650		)	(7,154		)
Deferred investment tax credits	(2,805		)	(2,807		)	(2,941		)
Total income tax expense	$	273,918		$	278,440		$	243,591

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

(Thousands of Dollars)	2016			2015			2014
Deferred tax expense excluding items below	$	230,931		$	285,144		$	254,142
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(8,418		)	(7,229		)	(26,649		)
Tax (expense) benefit allocated to other comprehensive income and other	(511		)	(19		)	330
Deferred tax expense	$	222,002		$	277,896		$	227,823

The components of the net deferred tax liability at Dec. 31 were as follows:

(Thousands of Dollars)	2016		2015
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,967,162	$	2,772,043
Employee benefits	87,693		105,049
Other	69,931		82,732
Total deferred tax liabilities	$	3,124,786	$	2,959,824
Deferred tax assets:
NOL carryforward	$	115,328	$	147,763
Tax credit carryforward	34,658		35,240
Regulatory liabilities	19,635		17,201
Deferred investment tax credits	11,653		12,718
Deferred fuel costs	10,070		29,694
Rate refund	7,221		23,352
Other	37,092		35,658
Total deferred tax assets	$	235,657	$	301,626
Net deferred tax liability	$	2,889,129	$	2,658,198

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, 2016, PSCo had 1,984 bargaining employees covered under a collective-bargaining agreement, which expires in May 2017.

53

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 NAVs.

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 commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, 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 NAV with proper notice. Proper notice varies by fund and can range from daily with a few 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. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or 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.

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.

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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, with distributions attributable to PSCo funded by PSCo’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2016 and 2015 were $43.5 million and $41.8 million, respectively, of which $3.8 million and $3.6 million were attributable to PSCo. In 2016 and 2015, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $7.9 million and $9.5 million, respectively, of which $0.6 million in each year was attributable to PSCo.

In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to PSCo will be supplemented by PSCo’s consolidated operating cash flows as determined necessary. The amount of rabbi trust funding attributable to PSCo is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options.

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 pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

• Investment returns in 2016 were below the assumed level of 6.84 percent;

• 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; and

• In 2017, PSCo’s expected investment-return assumption is 6.62 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:

	2016		2015
Domestic and international equity securities	36	%	36	%
Long-duration fixed income and interest rate swap securities	31		32
Short-to-intermediate fixed income securities	15		12
Alternative investments	16		18
Cash	2		2
Total	100	%	100	%

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

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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, 2016 and 2015:

	Dec. 31, 2016
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	34,957	$	—		$	—	$	—	$	34,957
Commingled funds:
U.S. equity funds	—		—			—		165,621		165,621
Non U.S. equity funds	—		—			—		122,197		122,197
U.S. corporate bond funds	—		—			—		96,995		96,995
Emerging market equity funds	—		—			—		64,784		64,784
Emerging market debt funds	—		—			—		53,703		53,703
Commodity funds	—		—			—		7,497		7,497
Private equity investments	—		—			—		31,828		31,828
Real estate	—		—			—		61,048		61,048
Other commingled funds	—		—			—		74,696		74,696
Debt securities:
Government securities	—		168,014			—		—		168,014
U.S. corporate bonds	—		86,081			—		—		86,081
Non U.S. corporate bonds	—		13,828			—		—		13,828
Mortgage-backed securities	—		2,179			—		—		2,179
Asset-backed securities	—		1,032			—		—		1,032
Equity securities:
U.S. equities	27,348		—			—		—		27,348
Other	—		(7,595		)	—		—		(7,595		)
Total	$	62,305	$	263,539		$	—	$	678,369	$	1,004,213

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	81,954	$	—		$	—	$	—	$	81,954
Derivatives	—		1,204			—		—		1,204
Commingled funds:
U.S. equity funds	—		—			—		125,011		125,011
Non U.S. equity funds	—		—			—		119,394		119,394
U.S. corporate bond funds	—		—			—		82,827		82,827
Emerging market equity funds	—		—			—		56,525		56,525
Emerging market debt funds	—		—			—		54,362		54,362
Commodity funds	—		—			—		14,169		14,169
Private equity investments	—		—			—		34,353		34,353
Real estate	—		—			—		67,075		67,075
Other commingled funds	—		—			—		72,327		72,327
Debt securities:
Government securities	—		214,341			—		—		214,341
U.S. corporate bonds	—		74,787			—		—		74,787
Non U.S. corporate bonds	—		12,127			—		—		12,127
Asset-backed securities	—		881			—		—		881
Equity securities:
U.S. equities	28,797		—			—		—		28,797
Other	—		(3,453		)	—		—		(3,453		)
Total	$	110,751	$	299,887		$	—	$	626,043	$	1,036,681

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014.

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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)	2016			2015
Accumulated Benefit Obligation at Dec. 31	$	1,213,890		$	1,192,798
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,224,650		$	1,277,957
Service cost	25,926			28,260
Interest cost	55,405			50,857
Transfer to other plan	(9,149		)	(2,938		)
Plan amendments	206			—
Actuarial loss (gain)	51,779			(54,737		)
Benefit payments	(96,995		)	(74,749		)
Obligation at Dec. 31	$	1,251,822		$	1,224,650

(Thousands of Dollars)	2016			2015
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,036,681		$	1,103,865
Actual return (loss) on plan assets	56,762			(9,122		)
Employer contributions	16,829			20,056
Transfer to other plan	(9,064		)	(3,369		)
Benefit payments	(96,995		)	(74,749		)
Fair value of plan assets at Dec. 31	$	1,004,213		$	1,036,681

(Thousands of Dollars)	2016			2015
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(247,609	)	$	(187,969	)

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

(Thousands of Dollars)	2016			2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	554,999		$	521,703
Prior service credit	(12,155		)	(15,572		)
Total	$	542,844		$	506,131

(Thousands of Dollars)	2016		2015
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	$	515,708	$	28,852
Noncurrent regulatory assets	26,853		477,279
Deferred income taxes	108		—
Net-of-tax accumulated OCI	175		—
Total	$	542,844	$	506,131

Measurement date Dec. 31, 2016 Dec. 31, 2015

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	2016		2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.13	%	4.66	%
Expected average long-term increase in compensation level	3.75		4.00
Mortality table	RP-2014		RP-2014

Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) and projection scale (MP-2014) that increased the overall life expectancy of males and females. On Dec. 31, 2014 PSCo adopted the RP-2014 table, with modifications, based on its population and specific experience and a modified MP-2014 projection scale. During 2016, a new projection table was released (MP-2016).  In 2016, PSCo adopted a modified version of the MP-2016 table and will continue to utilize the RP-2014 base table, modified for company experience.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2014 through 2017 to meet minimum funding requirements.

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

• $150.0 million in January 2017, of which $16.8 million was attributable to PSCo;

• $125.2 million in 2016, of which $16.8 million was attributable to PSCo;

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

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

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

Plan Amendments — The 2016 increase in the projected benefit obligation resulted from an increase in the annual credits contributed to the PSCo Bargaining Plan retirement spending account. In 2015, there were no plan amendments made which affected the projected benefit obligation.

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

(Thousands of Dollars)	2016			2015			2014
Service cost	$	25,926		$	28,260		$	23,939
Interest cost	55,405			50,857			53,277
Expected return on plan assets	(70,769		)	(72,590		)	(70,709		)
Amortization of prior service credit	(3,211		)	(3,136		)	(3,092		)
Amortization of net loss	26,771			36,377			33,892
Net periodic pension cost	34,122			39,768			37,307
Credits (costs) not recognized due to effects of regulation	3,364			(1,464		)	—
Net benefit cost recognized for financial reporting	$	37,486		$	38,304		$	37,307

	2016		2015		2014
Significant Assumptions Used to Measure Costs:
Discount rate	4.66	%	4.11	%	4.75	%
Expected average long-term increase in compensation level	4.00		3.75		3.75
Expected average long-term rate of return on assets	6.84		6.81		6.81

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In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to PSCo were $9.4 million, $9.9 million and $9.4 million in 2016, 2015 and 2014, 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 2017 pension cost calculations is 6.62 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 $9.9 million in 2016, $9.5 million in 2015 and $9.1 million in 2014.

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:

	2016		2015
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.

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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, 2016 and 2015:

	Dec. 31, 2016
(Thousands of Dollars)	Level 1		Level 2		Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	18,288	$	—	$	—	$	—	$	18,288
Insurance contracts	—		42,046		—		—		42,046
Commingled funds:
U.S. equity funds	—		—		—		48,462		48,462
U.S fixed income funds	—		—		—		24,132		24,132
Emerging market debt funds	—		—		—		27,089		27,089
Other commingled funds	—		—		—		48,922		48,922
Debt securities:
Government securities	—		33,600		—		—		33,600
U.S. corporate bonds	—		55,473		—		—		55,473
Non U.S. corporate bonds	—		15,384		—		—		15,384
Asset-backed securities	—		16,845		—		—		16,845
Mortgage-backed securities	—		25,563		—		—		25,563
Equity securities:
Non U.S. equities	36,462		—		—		—		36,462
Other	—		1,289		—		—		1,289
Total	$	54,750	$	190,200	$	—	$	148,605	$	393,555

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	17,524	$	—		$	—	$	—	$	17,524
Insurance contracts	—		42,123			—		—		42,123
Commingled funds:
U.S. equity funds	—		—			—		34,089		34,089
Non U.S. equity funds	—		—			—		29,979		29,979
U.S fixed income funds	—		—			—		21,638		21,638
Emerging market equity funds	—		—			—		9,901		9,901
Emerging market debt funds	—		—			—		31,827		31,827
Other commingled funds	—		—			—		55,302		55,302
Debt securities:
Government securities	—		35,016			—		—		35,016
U.S. corporate bonds	—		53,433			—		—		53,433
Non U.S. corporate bonds	—		11,598			—		—		11,598
Asset-backed securities	—		25,602			—		—		25,602
Mortgage-backed securities	—		31,778			—		—		31,778
Other	—		(368		)	—		—		(368		)
Total	$	17,524	$	199,182		$	—	$	182,736	$	399,442

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014.

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

(Thousands of Dollars)	2016			2015
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	403,574		$	443,753
Service cost	768			928
Interest cost	18,070			17,498
Medicare subsidy reimbursements	1,901			1,712
Plan participants’ contributions	5,376			4,961
Actuarial loss (gain)	27,355			(32,001		)
Benefit payments	(35,221		)	(33,277		)
Obligation at Dec. 31	$	421,823		$	403,574

(Thousands of Dollars)	2016			2015
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	399,442		$	425,282
Actual return (loss) on plan assets	18,590			(3,076		)
Plan participants’ contributions	5,376			4,961
Employer contributions	5,368			5,552
Benefit payments	(35,221		)	(33,277		)
Fair value of plan assets at Dec. 31	$	393,555		$	399,442

(Thousands of Dollars)	2016			2015
Funded Status at Dec. 31:
Funded status (a)	$	(28,268	)	$	(4,132	)

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

(Thousands of Dollars)	2016			2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	78,359		$	49,226
Prior service credit	(27,695		)	(33,942		)
Total	$	50,664		$	15,284

(Thousands of Dollars)	2016		2015
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	$	50,664	$	15,284

Measurement date Dec. 31, 2016 Dec. 31, 2015

	2016		2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.13	%	4.65	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	5.50	%	6.00	%

Effective Jan. 1, 2017, the initial medical trend rate was decreased from 6.0 percent to 5.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is two 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.

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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	$	40,100	$	(34,155	)
Service and interest components	1,980		(1,677		)

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 $17.9 million, $18.3 million and $17.1 million during 2016, 2015 and 2014, respectively, of which $5.4 million, $5.6 million and $5.5 million were attributable to PSCo. Xcel Energy expects to contribute approximately $11.8 million during 2017, of which amounts attributable to PSCo will be zero.

Plan Amendments — In 2016 and 2015 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)	2016			2015			2014
Service cost	$	768		$	928		$	1,915
Interest cost	18,070			17,498			23,704
Expected return on plan assets	(22,299		)	(23,803		)	(30,214		)
Amortization of prior service credit	(6,247		)	(6,247		)	(6,247		)
Amortization of net loss	1,931			2,475			6,434
Net periodic postretirement benefit credit	$	(7,777	)	$	(9,149	)	$	(4,408	)

	2016		2015		2014
Significant Assumptions Used to Measure Costs:
Discount rate	4.65	%	4.08	%	4.82	%
Expected average long-term rate of return on assets	5.80		5.80		7.18

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
2017	$	79,506	$	33,912	$	2,140	$	31,772
2018	78,738		33,652		2,266		31,386
2019	80,914		33,467		2,383		31,084
2020	81,095		33,991		2,475		31,516
2021	82,084		33,588		2,574		31,014
2022-2026	417,876		156,773		14,246		142,527

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9. Other Income, Net

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

(Thousands of Dollars)	2016			2015			2014
Interest income	$	1,860		$	753		$	1,470
Other nonoperating income	2,241			2,408			3,601
Insurance policy expense	(281		)	(197		)	(806		)
Other nonoperating expense	(3		)	—			—
Other income, net	$	3,817		$	2,964		$	4,265

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 NAVs.

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, 2016, accumulated other comprehensive losses related to interest rate derivatives included $1.0 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives.  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.

PSCo 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, 2016 and 2015.

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)	2016	2015
MWh of electricity	6,283	684
MMBtu of natural gas	42,203	12,515
Gallons of vehicle fuel	—	63

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

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

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.

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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, 2016, six of PSCo’s 10 most significant counterparties for these activities, comprising $8.8 million or 15 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  Four of the 10 most significant counterparties, comprising $21.1 million or 35 percent of this credit exposure at Dec. 31, 2016, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.  Seven 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)	2016			2015			2014
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,836	)	$	(23,878	)	$	(23,338	)
After-tax net unrealized (losses) related to derivatives accounted for as hedges	—			(30		)	(72		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	1,056			72			(468		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(22,780	)	$	(23,836	)	$	(23,878	)

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2016, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2016
	Pre-Tax Fair Value Gains 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 Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—	$	1,618	(a)	$	—		$	—
Vehicle fuel and other commodity	—		—		86		(b)	—			—
Total	$	—	$	—	$	1,704		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—	$	—		$	—		$	(257	)	(c)
Natural gas commodity	—		2,051		—			10,292		(d)	(5,832		)	(d)
Total	$	—	$	2,051	$	—		$	10,292		$	(6,089	)

	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		(d)	(7,620		)	(d)
Total	$	—		$	(10,635	)	$	—		$	10,158		$	(7,256	)

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	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	)	(d)	$	(9,850	)	(d)
Total	$	—		$	451	$	—			$	(4,631	)		$	(9,850	)

^(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 for the year ended Dec. 31, 2016 and Dec. 31, 2015 included $0.2 million and $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 were immaterial.  The remaining settlement losses for the years ended Dec. 31, 2016, 2015 and 2014 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, 2016, 2015 and 2014.  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, 2016 and 2015, there were no derivative instruments in a liability position with underlying contract provisions that 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, 2016 and 2015.

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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, 2016:

	Dec. 31, 2016
	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	$	1,124	$	5,453	$	—	$	6,577	$	(5,137	)	$	1,440
Natural gas commodity	—		7,778		—		7,778		—			7,778
Total current derivative assets	$	1,124	$	13,231	$	—	$	14,355	$	(5,137	)	9,218
PPAs (a)												1,716
Current derivative instruments												$	10,934
Noncurrent derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	1,652	$	—	$	1,652	$	—		$	1,652
Total noncurrent derivative assets	$	—	$	1,652	$	—	$	1,652	$	—		1,652
PPAs (a)												1,746
Noncurrent derivative instruments												$	3,398
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1,386	$	5,357	$	22	$	6,765	$	(5,137	)	$	1,628
Total current derivative liabilities	$	1,386	$	5,357	$	22	$	6,765	$	(5,137	)	1,628
PPAs (a)												5,160
Current derivative instruments												$	6,788
Noncurrent derivative liabilities
PPAs (a)												$	7,828
Noncurrent derivative instruments												$	7,828

^(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, 2016. At Dec. 31, 2016, 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, 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 on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015.  At Dec. 31, 2015, derivative assets and liabilities 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 immaterial losses recognized in earnings for level 3 commodity trading derivatives for the year ended Dec. 31, 2016. There were no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2015 and 2014.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2016, 2015 and 2014.

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Fair Value of Long-Term Debt

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

	2016				2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,216,206	$	4,491,570	$	4,105,596	$	4,376,875

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU No. 2015-03.

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

11. Rate Matters

Pending Regulatory Proceedings — CPUC

Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. The 2016 earnings test did not result in a material customer refund obligation as of Dec. 31, 2016. PSCo will file its 2016 earnings test with the CPUC in April 2017. 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 400 GWh in 2015 and 2016 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 2017 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual spending limit of $84.3 million.

In February 2017, the CPUC approved PSCo’s 2017-2018 DSM plan:

• A 2017 DSM electric budget of $80.4 million and a natural gas budget of $13.1 million; and

• A 2018 DSM electric budget of $77.7 million and a natural gas budget of $12.8 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 $5.8 million and $5.5 million in 2016 and 2015, respectively. The cumulative credit to the RESA regulatory liability balance was $116.3 million and $110.6 million at Dec. 31, 2016 and Dec. 31, 2015, 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 Dec. 31, 2017.

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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:

Advanced Grid Intelligence and Security Initiative — PSCo is pursuing projects to update and advance its electric distribution grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over energy usage and implement new rate structures.

Rush Creek Wind Farm — PSCo has gained approval to build, own and operate a 600 MW wind generation facility and proposed transmission line in Colorado.

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 2017 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, 2016, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2017	$	241.2	$	293.6	$	117.8
2018	143.1		185.7		69.0
2019	68.6		179.7		37.1
2020	48.5		184.3		36.6
2021	49.6		191.5		34.4
Thereafter	293.4		171.2		609.9
Total	$	844.4	$	1,206.0	$	904.8

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.

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Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $44.0 million, $69.5 million and $69.5 million in 2016, 2015 and 2014, respectively. At Dec. 31, 2016, 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)
2017	$	24.3	$	4.4
2018	20.1		—
2019	11.5		—
2020	3.0		—
2021	3.0		—
Thereafter	16.4		—
Total	$	78.3	$	4.4

^(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 $127.0 million and $132.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2016 and 2015, 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 $8.1 million, $8.2 million, and $7.2 million for 2016, 2015 and 2014, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(65.3		)	(57.2		)
Total property held under capital leases, net	$	155.9		$	164.0

The remainder of the leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $118.2 million, $130.5 million and $126.2 million for 2016, 2015 and 2014, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $102.4 million, $113.5 million and $110.1 million in 2016, 2015 and 2014, respectively, recorded to electric fuel and purchased power expenses.

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

(Millions of Dollars)	Operating Leases		PPA (a) (b) Operating Leases		Total Operating Leases		Capital Leases
2017	$	11.0	$	96.3	$	107.3	$	25.7
2018	10.2		96.6		106.8		25.3
2019	10.3		97.5		107.8		25.1
2020	10.3		98.4		108.7		24.9
2021	9.7		99.4		109.1		23.8
Thereafter	45.2		483.7		528.9		462.7
Total minimum obligation							587.5
Interest component of obligation							(431.6		)
Present value of minimum obligation							$	155.9

^(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 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 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 1,571 MW and 1,802 MW of capacity under long-term PPAs as of Dec. 31, 2016, and 2015, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032.

Environmental Contingencies

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

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

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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 2017. PSCo had accrued $1.7 million for both of these sites at Dec. 31, 2016 and 2015, 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.

Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published a final rule regulating the management and disposal of coal combustion residuals (“CCR” or coal ash) as a nonhazardous waste. In December 2016, the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which includes provisions that allow the CCR rule to be implemented through a state or federal based permit program and that give the EPA direct enforcement authority.  PSCo is in the process of evaluating whether the costs of implementing the CCR rule under the potential federal and/or state permit programs could have a material impact on the results of operations, financial position or cash flows.

In 2015, industry and environmental non-governmental organizations sought judicial review of the final CCR rule. In June 2016, the D.C. Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. A final court decision is anticipated in the first half of 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on PSCo. PSCo believes that these associated costs would be recoverable through regulatory mechanisms.

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In 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 capital cost to comply with the 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 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. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule.  In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected by June 2017.

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Air

GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, a final rule was published by the EPA for GHG emission standards for existing power plants.  Under the rule, states were required to develop implementation plans by September 2016, with the possibility of an extension to September 2018, or submit to a federal plan for the state prepared by the EPA.  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 was 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. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. During the pendency of the stay, states are not required to submit implementation plans and the EPA will not enforce deadlines or issue a federal plan for any state. Colorado is continuing formal planning efforts.

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 the state plan does not provide credit for the investments PSCo has already made to reduce GHG emissions, or if it requires additional initiatives or emission reductions, then its requirements would potentially impose additional substantial costs.  Until PSCo has more information about a SIP or the EPA finalizes its proposed federal plan 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 PSCo’s regulators do not allow recovery of 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.

Implementation of the NAAQS for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant. The Pawnee plant recently installed an SO₂ scrubber to reduce SO₂ emissions. In June 2016, the EPA issued final designations which found the area near the Pawnee plant is “unclassifiable.” It is anticipated that the area near the Pawnee plant will be able to show compliance with the NAAQS through air dispersion modeling performed by the Colorado Department of Public Health and Environment.

The areas near the remaining PSCo power plants, Comanche and Hayden, which utilize scrubbers to control SO₂ emissions, will be evaluated in the next designation phase, ending December 2017. In late 2016, PSCo submitted air dispersion modeling to the Colorado Department of Public Health and Environment and the EPA which demonstrated that PSCo’s Comanche and Hayden plants comply with the NAAQS. If an area is designated nonattainment in 2020, the states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. PSCo cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that should SO₂ control systems require upgrades for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

Revisions to the NAAQS for Ozone— In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard, however PSCo’s scheduled retirement of coal fired plants in Denver should help in any plan to mitigate non-attainment.

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, thermal 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.

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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 and radiation sources.

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, 2016 and 2015 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2016		Liabilities Recognized		Accretion		Cash Flow     Revisions (a)			Ending Balance      Dec. 31, 2016 (b)
Electric plant
Steam and other production asbestos	$	38,676	$	—	$	1,877	$	(103	)	$	40,450
Steam and other production ash containment	70,767		—		3,078		(1,245		)	72,600
Wind production	1,992		—		19		61			2,072
Electric distribution	1,130		—		45		6,494			7,669
Other	1,054		214		46		206			1,520
Natural gas plant
Gas transmission and distribution	122,168		—		5,009		33,542			160,719
Other	3,925		—		155		—			4,080
Common and other property
Common miscellaneous	796		—		28		(371		)	453
Total liability	$	240,508	$	214	$	10,257	$	38,584		$	289,563

^(a)  In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains.

^(b)  There were no ARO liabilities settled during the year ended Dec. 31, 2016.

(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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Indeterminate AROs— 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, 2016. 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, 2016 and 2015 were $367 million and $364 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) alleged between $34 million to $50 million in sales with PSCo were 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, the FERC rejected 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 February 2016, the City appealed this decision to the Ninth Circuit.

In October 2016, a settlement was reached that resolved all outstanding claims between and among the City and the respondents, including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth Circuit. These terms have been met, bringing this matter to a close.

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC filed a notice of appeal. The matter has been fully briefed and plaintiff has requested oral arguments. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in Denver District Court in August 2016. DRC filed its brief in February 2017 and PSCo’s answer brief will be due March 2017.

PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

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Other Contingencies

See Note 11 for further discussion.

13. Regulatory Assets and Liabilities

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

The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2016 and 2015 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2016				Dec. 31, 2015
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	27,270	$	568,258	$	29,260	$	497,973
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		151,022		—		144,953
Depreciation differences	1	Pending rate case	15,363		90,426		14,221		99,835
Net AROs (b)	1, 12	Plant lives	—		78,050		—		62,948
Purchased power contract costs	12	Term of related contract	1,035		29,029		1,319		29,143
Conservation programs (c)	1, 11	One to two years	9,262		6,986		8,466		6,947
Losses on reacquired debt	4	Term of related debt	1,203		6,120		1,421		6,957
Contract valuation adjustments (d)	10	Term of related contract	3,444		6,082		9,376		9,526
Gas pipeline inspection costs	12	Two years	—		4,405		3,611		—
Property tax		Various	9,393		1,653		21,558		14,428
CACJA recovery rider		Less than one year	24,260		—		—		20,020
Other		Various	12,553		16,398		2,840		13,545
Total regulatory assets			$	103,783	$	958,429	$	92,072	$	906,275

^(a)  Includes $4.2 million and $4.4 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2016 and 2015, respectively.

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

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

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

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The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2016 and 2015 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2016				Dec. 31, 2015
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	367,440	$	—	$	364,291
Renewable resources and environmental initiatives	11, 12	Various	3,600		67,728		3,311		40,988
Investment tax credit deferrals	1, 7	Various	—		18,797		—		20,515
Deferred income tax adjustment	1	Various	—		16,260		—		16,891
Gain from asset sales		Pending rate case	—		1,469		—		—
PSCo earnings test	11	One to two years	8,300		914		42,868		9,472
Deferred electric, natural gas and steam production costs	1	Less than one year	35,123		—		66,696		—
Conservation programs (a)	1, 11	Less than one year	24,077		—		33,460		—
Gas pipeline inspection costs	12	Less than one year	5,108		—		1,140		4,273
Low income discount program		Less than one year	881		—		1,393		—
Other		Various	24,021		40,325		3,955		14,991
Total regulatory liabilities (b)			$	101,110	$	512,933	$	152,823	$	471,421

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

^(b)  Revenue subject to refund of $2.4 million and $9.1 million for 2016 and 2015, respectively, is included in other current liabilities.

At Dec. 31, 2016 and 2015, approximately $28 million and $54 million of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with renewable resources and environmental initiatives.

14. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2016 and 2015 were as follows:

	Year Ended Dec. 31, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(23,836	)	$	—		$	(23,836	)
Other comprehensive loss before reclassifications	—			(223		)	(223		)
Losses reclassified from net accumulated other comprehensive loss	1,056			3			1,059
Net current period other comprehensive income (loss)	1,056			(220		)	836
Accumulated other comprehensive loss at Dec. 31	$	(22,780	)	$	(220	)	$	(23,000	)

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

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Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2016				Year Ended Dec. 31, 2015
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	1,618		(a)	$	54		(a)
Vehicle fuel derivatives	86			(b)	57			(b)
Total, pre-tax	1,704				111
Tax benefit	(648		)		(39		)
Total, net of tax	1,056				72
Defined benefit pension and postretirement losses (gains):
Amortization of net losses	5			(c)	—
Total, pre-tax	5				—
Tax benefit	(2		)		—
Total, net of tax	3				—
Total amounts reclassified, net of tax	$	1,059			$	72

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

^(c)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans.

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
2016
Operating revenues (a)	$	3,049,352	$	957,721	$	40,723		$	—		$	4,047,796
Intersegment revenues	275		110		—			(385		)	—
Total revenues	$	3,049,627	$	957,831	$	40,723		$	(385	)	$	4,047,796
Depreciation and amortization	$	337,583	$	101,663	$	4,309		$	—		$	443,555
Interest charges and financing costs	136,274		37,881		431			—			174,586
Income tax expense (benefit)	228,825		45,960		(867		)	—			273,918
Net income	383,973		75,426		4,092			—			463,491

(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

^(a)  Operating revenues include $13 million, $13 million and $14 million of intercompany revenue for the years ended Dec. 31, 2016, 2015 and 2014, 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)	2016		2015		2014
Operating revenues:
Electric	$	8,809	$	8,632	$	9,614
Other	4,525		4,441		4,441
Operating expenses:
Purchased power	56		—		23
Other operating expenses — paid to Xcel Energy Services Inc.	446,086		414,620		454,250
Interest expense	149		211		158
Interest income	—		45		61

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

	2016				2015
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	7,669	$	—	$	4,419	$	—
NSP-Wisconsin	974		—		71		—
SPS	745		—		414		—
Other subsidiaries of Xcel Energy Inc.	33		98,797		5		76,643
	$	9,421	$	98,797	$	4,909	$	76,643

17. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2016		June 30, 2016		Sept. 30, 2016		Dec. 31, 2016
Operating revenues	$	1,057,841	$	909,852	$	1,059,177	$	1,020,926
Operating income	223,190		180,629		315,605		170,197
Net income	115,874		87,344		173,607		86,666

	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

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, 2016, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

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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, 2016 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.

In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. PSCo plans to initiate deployment of work management systems modules, including the conversion of existing work management systems, to this same system during 2017. 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 systems. 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 2017 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 2017 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2017. 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, 2016.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2016, 2015, and 2014.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2016, 2015, and 2014.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2016, 2015, and 2014.
	Consolidated Balance Sheets — As of Dec. 31, 2016 and 2015.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2016, 2015 and 2014.
	Consolidated Statements of Capitalization — As of Dec. 31, 2016 and 2015.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2016, 2015, and 2014.
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).

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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 million 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)).
4.14*	Supplemental Indenture dated as of June 1, 2016 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 3.55 percent First Mortgage Bonds, Series No. 29 due 2046. (Exhibit 4.01 to Form 8-K of PSCo dated June 13, 2016 (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).

84

10.13*+	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).
10.14*+	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).
10.15*+	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).
10.16*+	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).
10.17*+	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).
10.18*+	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).
10.19*+	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).
10.20*+	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).
10.21*+	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).
10.22*+	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).
10.23*+	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).
10.24*+	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).
10.25*+	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).
10.26*+	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).
10.27*+	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).
10.28*+	Fifth Amendment dated May 3, 2016 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2016).
10.29*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 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 and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.03 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).
10.30*+	Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2016).
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 10.33 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2016).

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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, 2016 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) 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.

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SCHEDULE II

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2016, 2015 AND 2014

(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:
2016	$	20,122	$	14,121	$	4,447	$	19,078	$	19,612
2015	23,122		13,052		5,175		21,227		20,122
2014	22,505		17,005		6,240		22,628		23,122

^(a)  Recovery of amounts previously written off.

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

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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. 24, 2017	/s/ ROBERT C. FRENZEL
	Robert C. Frenzel
	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/ ROBERT C. FRENZEL	/s/ JEFFREY S. SAVAGE
Robert C. Frenzel	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
	2016		2015		2014		2013		2012
Earnings, as defined:
Pretax income	$	737,409	$	745,242	$	698,779	$	704,123	$	690,620
Add: Fixed charges	236,080		235,530		232,832		232,539		254,443
Total earnings, as defined	$	973,489	$	980,772	$	931,611	$	936,662	$	945,063
Fixed charges, as defined:
Interest charges	$	181,631	$	177,430	$	171,881	$	173,602	$	188,094
Interest charges on life insurance policy borrowings	203		233		214		245		310
Interest component of leases	54,246		57,867		60,737		58,692		66,039
Total fixed charges, as defined	$	236,080	$	235,530	$	232,832	$	232,539	$	254,443
Ratio of earnings to fixed charges	4.1		4.2		4.0		4.0		3.7

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-203664-04 on Form S-3 of our report dated February 24, 2017, 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, 2016.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2017

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. 24, 2017

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Robert C. Frenzel, 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. 24, 2017

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

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, 2016, 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. 24, 2017

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

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.

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 24, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	PUBLIC SERVICE CO OF COLORADO
Entity Central Index Key	0000081018
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		100
Document Type	10-K
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Amendment Flag	false
Document Period End Date	Dec. 31, 2016

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues
Electric	$ 3,049,352	$ 3,115,257	$ 3,125,937
Natural gas	957,721	1,006,666	1,215,324
Steam and other	40,723	41,590	41,888
Total operating revenues	4,047,796	4,163,513	4,383,149
Operating expenses
Electric fuel and purchased power	1,196,417	1,246,666	1,405,498
Cost of natural gas sold and transported	425,410	501,824	725,754
Cost of sales — steam and other	15,872	17,788	16,831
Operating and maintenance expenses	762,416	761,901	751,786
Demand side management program expenses	118,175	128,681	139,780
Depreciation and amortization	443,555	411,667	379,202
Taxes (other than income taxes)	196,330	195,285	161,928
Total operating expenses	3,158,175	3,263,812	3,580,779
Operating income	889,621	899,701	802,370
Other income, net	3,817	2,964	4,265
Allowance for funds used during construction — equity	18,557	14,485	46,784
Interest charges and financing costs
Interest charges — includes other financing costs of $6,289, $6,285 and $6,340, respectively	181,631	177,430	171,881
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(7,045)	(5,522)	(17,241)
Total interest charges and financing costs	174,586	171,908	154,640
Income before income taxes	737,409	745,242	698,779
Income taxes	273,918	278,440	243,591
Net income	$ 463,491	$ 466,802	$ 455,188

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest charges and financing costs
Other financing costs	$ 6,289	$ 6,285	$ 6,340

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Comprehensive income:
Net income	$ 463,491	$ 466,802	$ 455,188
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $(138), $0, and $0	(223)	0	0
Amortization of losses included in net periodic benefit cost, net of tax of $2, $0, and $0, respectively	3	0	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	(220)	0	0
Derivative instruments:
Net fair value decrease, net of tax of $0, $(20), and $(43), respectively	0	(30)	(72)
Reclassification of losses (gains) to net income, net of tax of $648, $39, and $(287), respectively	1,056	72	(468)
Total derivative instruments, net of tax	1,056	42	(540)
Other comprehensive income (loss)	836	42	(540)
Comprehensive income	$ 464,327	$ 466,844	$ 454,648

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other comprehensive income (loss)
Amortization of losses included in net periodic benefit cost, tax	$ 2	$ 0	$ 0
Derivative instruments:
Net fair value (decrease) increase, tax	0	(20)	(43)
Reclassification of losses (gains) to net income, tax	648	39	(287)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ (138)	$ 0	$ 0

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities
Net income	$ 463,491	$ 466,802	$ 455,188
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	446,179	416,427	383,992
Demand side management program amortization	2,138	3,509	4,331
Deferred income taxes	222,002	277,896	227,823
Amortization of Investment Tax Credits	(2,805)	(2,807)	(2,941)
Allowance for equity funds used during construction	(18,557)	(14,485)	(46,784)
Provision for bad debts	14,121	13,052	17,005
Net realized and unrealized hedging and derivative transactions	1,325	2,414	(2,578)
Other Operating Activities, Cash Flow Statement	(388)	2,500	0
Changes in operating assets and liabilities:
Accounts receivable	(14,227)	8,872	(42,921)
Accrued unbilled revenues	(20,866)	17,837	(23,132)
Inventories	172	33,417	(972)
Prepayments and other	68,693	10,483	(81,715)
Accounts payable	38,439	(40,982)	(22,789)
Net regulatory assets and liabilities	4,143	78,055	130,499
Other current liabilities	1,892	19,654	5,284
Pension and other employee benefit obligations	(10,627)	(23,449)	(38,905)
Change in other noncurrent assets	(6,750)	4,086	5,537
Change in other noncurrent liabilities	(22,120)	(35,334)	(19,130)
Net cash provided by (used in) operating activities	1,166,255	1,237,947	947,792
Investing activities
Utility capital/construction expenditures	(1,113,800)	(995,597)	(1,114,338)
Proceeds from Insurance Settlement, Investing Activities	608	0	0
Allowance for equity funds used during construction	18,557	14,485	46,784
Investments in utility money pool arrangement	(444,000)	(196,300)	(603,000)
Repayments from utility money pool arrangement	444,000	212,300	659,000
Payments for (Proceeds from) Other Investing Activities	(1,460)	0	0
Net cash provided by (used in) investing activities	(1,096,095)	(965,112)	(1,011,554)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	115,000	(368,000)	382,000
Borrowings under utility money pool arrangement	524,500	165,000	333,000
Repayments under utility money pool arrangement	(524,500)	(165,000)	(333,000)
Proceeds from issuance of long-term debt	244,507	246,751	295,598
Repayments of long-term debt	(129,500)	0	(275,000)
Capital contributions from parent	38,755	175,210	81,498
Dividends paid to parent	(336,581)	(330,846)	(433,788)
Net cash provided by (used in) financing activities	(67,819)	(276,885)	50,308
Net change in cash and cash equivalents	2,341	(4,050)	(13,454)
Cash and cash equivalents at beginning of period	3,585	7,635	21,089
Cash and cash equivalents at end of period	5,926	3,585	7,635
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(171,714)	(165,546)	(150,011)
Cash received (paid) for income taxes, net	22,827	13,822	(91,810)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 68,870	$ 106,912	$ 139,616

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents		$ 5,926	$ 3,585
Accounts receivable, net		304,900	300,882
Accounts receivable from affiliates		9,421	4,909
Accrued unbilled revenues		297,078	276,212
Inventories		202,220	205,562
Regulatory assets		103,783	92,072
Derivative instruments		10,934	1,945
Prepaid Taxes		9,124	81,162
Prepayments and other		25,435	22,698
Total current assets		968,821	989,027
Property, plant and equipment, net		12,849,799	12,172,211
Other assets
Regulatory assets		958,429	906,275
Derivative instruments		3,398	3,478
Other		25,637	18,224
Total other assets		987,464	927,977
Total assets		14,806,084	14,089,215
Current liabilities
Current portion of long-term debt		5,270	8,103
Short-term debt		129,000	14,000
Accounts payable		376,186	352,701
Accounts payable to affiliates		98,797	76,643
Regulatory liabilities	[1]	101,110	152,823
Taxes accrued		171,862	166,660
Accrued interest		48,619	49,698
Dividends payable to parent		74,208	83,374
Derivative instruments		6,788	8,881
Other		73,022	78,910
Total current liabilities		1,084,862	991,793
Deferred credits and other liabilities
Deferred income taxes		2,889,129	2,658,198
Deferred investment tax credits		30,661	33,466
Regulatory liabilities		512,933	471,421
Asset retirement obligations		289,563	240,508
Derivative instruments		7,828	13,020
Customer advances		162,742	198,526
Pension and employee benefit obligations		285,774	200,774
Other		62,201	63,864
Total deferred credits and other liabilities		4,240,831	3,879,777
Commitments and contingencies
Capitalization
Long-term debt		4,210,936	4,097,493
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively		0	0
Additional paid in capital		3,633,216	3,620,824
Retained earnings		1,659,239	1,523,164
Accumulated other comprehensive loss		(23,000)	(23,836)
Total common stockholder’s equity		5,269,455	5,120,152
Total liabilities and equity		$ 14,806,084	$ 14,089,215

[1] (b) Revenue subject to refund of $2.4 million and $9.1 million for 2016 and 2015, respectively, is included in other current liabilities.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
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, 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
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
Increase (Decrease) in Stockholder's Equity
Net income	$ 463,491			463,491
Other comprehensive income (loss)	836				836
Common dividends declared to parent	(327,416)			(327,416)
Contribution of capital by parent	12,392		12,392
Ending Balance at Dec. 31, 2016	$ 5,269,455	$ 0	$ 3,633,216	$ 1,659,239	$ (23,000)
Balance (in shares) at Dec. 31, 2016	100	100

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CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized Debt Issuance Expense		$ (26,799)	$ (26,595)
Debt Instrument, Unamortized Discount (Premium), Net		(12,922)	(11,340)
Total long-term debt		4,216,206	4,105,596
Less current maturities		5,270	8,103
Long-term Debt and Capital Lease Obligations		4,210,936	4,097,493
Common Stockholder's Equity
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively.		0	0
Additional paid in capital		3,633,216	3,620,824
Retained earnings		1,659,239	1,523,164
Accumulated other comprehensive loss		(23,000)	(23,836)
Total common stockholder’s equity		5,269,455	5,120,152
First Mortgage Bonds | Series Due Sept. 1, 2017
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	[1]	0	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
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		250,000	250,000
First Mortgage Bonds | Series Due Sept. 1, 2037
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		350,000	350,000
First Mortgage Bonds | Series Due Aug. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		300,000	300,000
First Mortgage Bonds | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		250,000	250,000
First Mortgage Bonds | Series Due Sept. 15, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		500,000	500,000
First Mortgage Bonds | Series Due March 15, 2043
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		250,000	250,000
First Mortgage Bonds | Series Due March 15, 2044
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		300,000	300,000
First Mortgage Bonds | Series Due June 15, 2046 [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		250,000	0
Capital Lease Obligations
Schedule of Capitalization, Long-term Debt [Line Items]
Capital lease obligations		$ 155,927	$ 164,031

[1] Pollution control financing.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Common Stockholders Equity [Abstract]
Common stock, shares authorized (in shares)	100	100
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	100	100
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%
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%
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%
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%
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%
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%
Maturity Date	Mar. 15, 2023	Mar. 15, 2023
First Mortgage Bonds | Series Due May 15, 2025
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	2.90%
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%
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%
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%
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%
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%
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%
Maturity Date	Mar. 15, 2044	Mar. 15, 2044
First Mortgage Bonds | Series Due June 15, 2046 [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	3.55%
Maturity Date	Jun. 15, 2046
Capital Lease Obligations
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, maturity date range, end	Dec. 31, 2060
Capital Lease Obligations | Minimum
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	11.20%
Capital Lease Obligations | Maximum
Schedule of Capitalization, Long-term Debt [Line Items]
Interest rate, stated percentage (in hundredths)	14.30%

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

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 as alternative revenue programs under GAAP. 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 C&I 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 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 2.6, 2.7 and 2.7 percent for the years ended Dec. 31, 2016, 2015 and 2014, 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 tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.

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

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

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

See Note 7 for further discussion of income taxes.

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

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and 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 NAVs.  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.

Reclassifications— Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation. See Note 2 for further discussion of recently adopted accounting pronouncements.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

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Accounting Pronouncements

12 Months Ended

Dec. 31, 2016

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 new framework for the recognition of revenue. PSCo expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs in the consolidated statements of income. PSCo has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination of whether receipts of non-refundable contributions in aid of construction should be recognized as revenues or may continue to be recorded as reductions to property, plant and equipment. Also, it is yet to be determined whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts of revenue recognized upon delivery. PSCo currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

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 No. 2016-01 on its consolidated financial statements.

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

Recently Adopted

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its consolidated financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. PSCo implemented the new guidance as required on Jan. 1, 2016, and as a result, $26.6 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a NAV methodology in the fair value hierarchy. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No. 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the consolidated 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. PSCo early adopted the new guidance in the fourth quarter of 2016 and as a result $62.7 million of current deferred income taxes were retrospectively reclassified to long-term deferred income tax liabilities on the consolidated balance sheet as of Dec. 31, 2015.

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. PSCo adopted the guidance in 2016, and the implementation did not have a material impact on its consolidated financial statements.

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Selected Balance Sheet Data

12 Months Ended

Dec. 31, 2016

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	324,512		$	321,004
Less allowance for bad debts	(19,612		)	(20,122		)
	$	304,900		$	300,882

(Thousands of Dollars)	Dec. 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	66,161	$	58,128
Fuel	66,429		78,586
Natural gas	69,630		68,848
	$	202,220	$	205,562

(Thousands of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	12,304,436		$	11,856,126
Natural gas plant	3,710,772			3,420,249
Common and other property	919,955			862,840
Plant to be retired (a)	31,839			38,249
Construction work in progress	484,340			408,963
Total property, plant and equipment	17,451,342			16,586,427
Less accumulated depreciation	(4,601,543		)	(4,414,216		)
	$	12,849,799		$	12,172,211

^(a)  In 2017, PSCo expects to early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired by approximately 2025.  Amounts are presented net of accumulated depreciation.

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Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2016
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	56
Maximum amount outstanding	141
Weighted average interest rate, computed on a daily basis	0.78		%
Weighted average interest rate at period end	N/A

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	21			1			4
Maximum amount outstanding	141			34			97
Weighted average interest rate, computed on a daily basis	0.73		%	0.41		%	0.25		%
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, 2016
Borrowing limit	$	700
Amount outstanding at period end	129
Average amount outstanding	33
Maximum amount outstanding	151
Weighted average interest rate, computed on a daily basis	0.78		%
Weighted average interest rate at period end	0.95

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	129			14			382
Average amount outstanding	24			95			167
Maximum amount outstanding	154			449			393
Weighted average interest rate, computed on a daily basis	0.70		%	0.51		%	0.31		%
Weighted average interest rate at period end	0.95			0.60			0.65

Letters of Credit— PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2016 and 2015, there were $3 million and $4 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

Amended Credit Agreement— In June 2016, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $700 million. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions:

• The maturity extended from October 2019 to June 2021.

• The Eurodollar borrowing margin on this line of credit was reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.

• The commitment fees, calculated on the unused portion of the line of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

PSCo has the right to request an extension of the termination date for two additional one-year periods. The 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 at both Dec. 31, 2016 and 2015. 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, 2016 and 2015.

At Dec. 31, 2016, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700	$	132	$	568

^(a)  This credit facility matures in June 2021.

^(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, 2016 and 2015.

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 2016, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046. In 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025.

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

Deferred Financing Costs— Deferred financing costs of approximately $26.8 million and $26.6 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2016 and 2015, 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, 2016

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, 2016

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, 2016:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	149,221	$	67,415	$	97	76	%
Hayden Unit 2	148,795		64,024		64		37
Hayden Common Facilities	38,230		18,951		282		53
Craig Units 1 and 2	60,318		37,570		15,730		10
Craig Common Facilities 1, 2 and 3	37,925		19,312		183		7
Comanche Unit 3	892,978		112,254		6		67
Comanche Common Facilities	24,694		1,821		636		82
Electric Transmission:
Transmission and other facilities, including substations	166,840		65,619		4,313		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	23,406		7,679		—		60
Gas Transportation Compressor	8,397		368		—		50
Total	$	1,550,804	$	395,013	$	21,311

PSCo has approximately 816 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, 2016

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.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the IRS commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of Dec. 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their cases to 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, following extensions, expires in December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’ proposed adjustment of the carryback claims. PSCo is not expected to accrue any income tax expense related to this adjustment.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013. Subsequent to year-end, the IRS proposed an adjustment to tax years 2012 through 2013 that may impact Xcel Energy’s NOL and tax credit carryforwards and ETR. However, Xcel Energy is continuing to evaluate the IRS’ proposal and the outcome and timing of a resolution is uncertain.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2016, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits— The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.9	$	2.4
Unrecognized tax benefit — Temporary tax positions	16.8		15.0
Total unrecognized tax benefit	$	19.7	$	17.4

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

(Millions of Dollars)	2016			2015			2014
Balance at Jan. 1	$	17.4		$	11.9		$	8.4
Additions based on tax positions related to the current year	2.7			4.5			3.7
Reductions based on tax positions related to the current year	—			(1.5		)	(0.7		)
Additions for tax positions of prior years	0.5			2.5			2.8
Reductions for tax positions of prior years	(0.9		)	—			(1.2		)
Settlements with taxing authorities	—			—			(1.1		)
Balance at Dec. 31	$	19.7		$	17.4		$	11.9

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, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.8	)	$	(4.3	)

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

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)	2016			2015			2014
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.4	)	$	(0.2	)	$	(0.1	)
Interest expense related to unrecognized tax benefits	(0.7		)	(0.2		)	(0.1		)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(1.1	)	$	(0.4	)	$	(0.2	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2016, 2015 or 2014.

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)	2016			2015
Federal NOL carryforward	$	260		$	328
Federal tax credit carryforwards	25			24
State NOL carryforwards	684			684
State tax credit carryforwards, net of federal detriment (a)	13			13
Valuation allowances for state credit carryforwards, net of federal detriment (b)	(3		)	(1		)

^(a)  State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2016 and 2015, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $1 million as of Dec. 31, 2016 and 2015, respectively.

The federal carryforward periods expire between 2021 and 2036.  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:

	2016		2015		2014
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		3.2		2.8
Tax credits recognized, net of federal income tax expense	(0.7	)	(0.7	)	(0.8	)
Regulatory differences — utility plant items	(0.5	)	(0.3	)	(2.1	)
Change in unrecognized tax benefits (expense)	—		0.1		(0.1	)
Other, net	0.1		0.1		0.1
Effective income tax rate	37.1	%	37.4	%	34.9	%

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

(Thousands of Dollars)	2016			2015			2014
Current federal tax expense (benefit)	$	45,287		$	(1,166	)	$	9,550
Current state tax expense (benefit)	8,754			(727		)	2,611
Current change in unrecognized tax expense	680			5,244			6,548
Deferred federal tax expense	195,064			246,096			208,781
Deferred state tax expense	27,216			36,450			26,196
Deferred change in unrecognized tax benefit	(278		)	(4,650		)	(7,154		)
Deferred investment tax credits	(2,805		)	(2,807		)	(2,941		)
Total income tax expense	$	273,918		$	278,440		$	243,591

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

(Thousands of Dollars)	2016			2015			2014
Deferred tax expense excluding items below	$	230,931		$	285,144		$	254,142
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(8,418		)	(7,229		)	(26,649		)
Tax (expense) benefit allocated to other comprehensive income and other	(511		)	(19		)	330
Deferred tax expense	$	222,002		$	277,896		$	227,823

The components of the net deferred tax liability at Dec. 31 were as follows:

(Thousands of Dollars)	2016		2015
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,967,162	$	2,772,043
Employee benefits	87,693		105,049
Other	69,931		82,732
Total deferred tax liabilities	$	3,124,786	$	2,959,824
Deferred tax assets:
NOL carryforward	$	115,328	$	147,763
Tax credit carryforward	34,658		35,240
Regulatory liabilities	19,635		17,201
Deferred investment tax credits	11,653		12,718
Deferred fuel costs	10,070		29,694
Rate refund	7,221		23,352
Other	37,092		35,658
Total deferred tax assets	$	235,657	$	301,626
Net deferred tax liability	$	2,889,129	$	2,658,198

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Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2016

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, 2016, PSCo had 1,984 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 NAVs.

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 commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, 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 NAV with proper notice. Proper notice varies by fund and can range from daily with a few 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. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or 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.

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, with distributions attributable to PSCo funded by PSCo’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2016 and 2015 were $43.5 million and $41.8 million, respectively, of which $3.8 million and $3.6 million were attributable to PSCo. In 2016 and 2015, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $7.9 million and $9.5 million, respectively, of which $0.6 million in each year was attributable to PSCo.

In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to PSCo will be supplemented by PSCo’s consolidated operating cash flows as determined necessary. The amount of rabbi trust funding attributable to PSCo is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options.

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 pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

• Investment returns in 2016 were below the assumed level of 6.84 percent;

• 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; and

• In 2017, PSCo’s expected investment-return assumption is 6.62 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:

	2016		2015
Domestic and international equity securities	36	%	36	%
Long-duration fixed income and interest rate swap securities	31		32
Short-to-intermediate fixed income securities	15		12
Alternative investments	16		18
Cash	2		2
Total	100	%	100	%

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

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2016 and 2015:

	Dec. 31, 2016
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	34,957	$	—		$	—	$	—	$	34,957
Commingled funds:
U.S. equity funds	—		—			—		165,621		165,621
Non U.S. equity funds	—		—			—		122,197		122,197
U.S. corporate bond funds	—		—			—		96,995		96,995
Emerging market equity funds	—		—			—		64,784		64,784
Emerging market debt funds	—		—			—		53,703		53,703
Commodity funds	—		—			—		7,497		7,497
Private equity investments	—		—			—		31,828		31,828
Real estate	—		—			—		61,048		61,048
Other commingled funds	—		—			—		74,696		74,696
Debt securities:
Government securities	—		168,014			—		—		168,014
U.S. corporate bonds	—		86,081			—		—		86,081
Non U.S. corporate bonds	—		13,828			—		—		13,828
Mortgage-backed securities	—		2,179			—		—		2,179
Asset-backed securities	—		1,032			—		—		1,032
Equity securities:
U.S. equities	27,348		—			—		—		27,348
Other	—		(7,595		)	—		—		(7,595		)
Total	$	62,305	$	263,539		$	—	$	678,369	$	1,004,213

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	81,954	$	—		$	—	$	—	$	81,954
Derivatives	—		1,204			—		—		1,204
Commingled funds:
U.S. equity funds	—		—			—		125,011		125,011
Non U.S. equity funds	—		—			—		119,394		119,394
U.S. corporate bond funds	—		—			—		82,827		82,827
Emerging market equity funds	—		—			—		56,525		56,525
Emerging market debt funds	—		—			—		54,362		54,362
Commodity funds	—		—			—		14,169		14,169
Private equity investments	—		—			—		34,353		34,353
Real estate	—		—			—		67,075		67,075
Other commingled funds	—		—			—		72,327		72,327
Debt securities:
Government securities	—		214,341			—		—		214,341
U.S. corporate bonds	—		74,787			—		—		74,787
Non U.S. corporate bonds	—		12,127			—		—		12,127
Asset-backed securities	—		881			—		—		881
Equity securities:
U.S. equities	28,797		—			—		—		28,797
Other	—		(3,453		)	—		—		(3,453		)
Total	$	110,751	$	299,887		$	—	$	626,043	$	1,036,681

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014.

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)	2016			2015
Accumulated Benefit Obligation at Dec. 31	$	1,213,890		$	1,192,798
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,224,650		$	1,277,957
Service cost	25,926			28,260
Interest cost	55,405			50,857
Transfer to other plan	(9,149		)	(2,938		)
Plan amendments	206			—
Actuarial loss (gain)	51,779			(54,737		)
Benefit payments	(96,995		)	(74,749		)
Obligation at Dec. 31	$	1,251,822		$	1,224,650

(Thousands of Dollars)	2016			2015
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,036,681		$	1,103,865
Actual return (loss) on plan assets	56,762			(9,122		)
Employer contributions	16,829			20,056
Transfer to other plan	(9,064		)	(3,369		)
Benefit payments	(96,995		)	(74,749		)
Fair value of plan assets at Dec. 31	$	1,004,213		$	1,036,681

(Thousands of Dollars)	2016			2015
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(247,609	)	$	(187,969	)

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

(Thousands of Dollars)	2016			2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	554,999		$	521,703
Prior service credit	(12,155		)	(15,572		)
Total	$	542,844		$	506,131

(Thousands of Dollars)	2016		2015
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	$	515,708	$	28,852
Noncurrent regulatory assets	26,853		477,279
Deferred income taxes	108		—
Net-of-tax accumulated OCI	175		—
Total	$	542,844	$	506,131

Measurement date Dec. 31, 2016 Dec. 31, 2015

	2016		2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.13	%	4.66	%
Expected average long-term increase in compensation level	3.75		4.00
Mortality table	RP-2014		RP-2014

Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) and projection scale (MP-2014) that increased the overall life expectancy of males and females. On Dec. 31, 2014 PSCo adopted the RP-2014 table, with modifications, based on its population and specific experience and a modified MP-2014 projection scale. During 2016, a new projection table was released (MP-2016).  In 2016, PSCo adopted a modified version of the MP-2016 table and will continue to utilize the RP-2014 base table, modified for company experience.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2014 through 2017 to meet minimum funding requirements.

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

• $150.0 million in January 2017, of which $16.8 million was attributable to PSCo;

• $125.2 million in 2016, of which $16.8 million was attributable to PSCo;

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

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

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

Plan Amendments — The 2016 increase in the projected benefit obligation resulted from an increase in the annual credits contributed to the PSCo Bargaining Plan retirement spending account. In 2015, there were no plan amendments made which affected the projected benefit obligation.

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

(Thousands of Dollars)	2016			2015			2014
Service cost	$	25,926		$	28,260		$	23,939
Interest cost	55,405			50,857			53,277
Expected return on plan assets	(70,769		)	(72,590		)	(70,709		)
Amortization of prior service credit	(3,211		)	(3,136		)	(3,092		)
Amortization of net loss	26,771			36,377			33,892
Net periodic pension cost	34,122			39,768			37,307
Credits (costs) not recognized due to effects of regulation	3,364			(1,464		)	—
Net benefit cost recognized for financial reporting	$	37,486		$	38,304		$	37,307

	2016		2015		2014
Significant Assumptions Used to Measure Costs:
Discount rate	4.66	%	4.11	%	4.75	%
Expected average long-term increase in compensation level	4.00		3.75		3.75
Expected average long-term rate of return on assets	6.84		6.81		6.81

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to PSCo were $9.4 million, $9.9 million and $9.4 million in 2016, 2015 and 2014, 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 2017 pension cost calculations is 6.62 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 $9.9 million in 2016, $9.5 million in 2015 and $9.1 million in 2014.

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:

	2016		2015
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, 2016 and 2015:

	Dec. 31, 2016
(Thousands of Dollars)	Level 1		Level 2		Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	18,288	$	—	$	—	$	—	$	18,288
Insurance contracts	—		42,046		—		—		42,046
Commingled funds:
U.S. equity funds	—		—		—		48,462		48,462
U.S fixed income funds	—		—		—		24,132		24,132
Emerging market debt funds	—		—		—		27,089		27,089
Other commingled funds	—		—		—		48,922		48,922
Debt securities:
Government securities	—		33,600		—		—		33,600
U.S. corporate bonds	—		55,473		—		—		55,473
Non U.S. corporate bonds	—		15,384		—		—		15,384
Asset-backed securities	—		16,845		—		—		16,845
Mortgage-backed securities	—		25,563		—		—		25,563
Equity securities:
Non U.S. equities	36,462		—		—		—		36,462
Other	—		1,289		—		—		1,289
Total	$	54,750	$	190,200	$	—	$	148,605	$	393,555

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	17,524	$	—		$	—	$	—	$	17,524
Insurance contracts	—		42,123			—		—		42,123
Commingled funds:
U.S. equity funds	—		—			—		34,089		34,089
Non U.S. equity funds	—		—			—		29,979		29,979
U.S fixed income funds	—		—			—		21,638		21,638
Emerging market equity funds	—		—			—		9,901		9,901
Emerging market debt funds	—		—			—		31,827		31,827
Other commingled funds	—		—			—		55,302		55,302
Debt securities:
Government securities	—		35,016			—		—		35,016
U.S. corporate bonds	—		53,433			—		—		53,433
Non U.S. corporate bonds	—		11,598			—		—		11,598
Asset-backed securities	—		25,602			—		—		25,602
Mortgage-backed securities	—		31,778			—		—		31,778
Other	—		(368		)	—		—		(368		)
Total	$	17,524	$	199,182		$	—	$	182,736	$	399,442

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014.

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

(Thousands of Dollars)	2016			2015
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	403,574		$	443,753
Service cost	768			928
Interest cost	18,070			17,498
Medicare subsidy reimbursements	1,901			1,712
Plan participants’ contributions	5,376			4,961
Actuarial loss (gain)	27,355			(32,001		)
Benefit payments	(35,221		)	(33,277		)
Obligation at Dec. 31	$	421,823		$	403,574

(Thousands of Dollars)	2016			2015
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	399,442		$	425,282
Actual return (loss) on plan assets	18,590			(3,076		)
Plan participants’ contributions	5,376			4,961
Employer contributions	5,368			5,552
Benefit payments	(35,221		)	(33,277		)
Fair value of plan assets at Dec. 31	$	393,555		$	399,442

(Thousands of Dollars)	2016			2015
Funded Status at Dec. 31:
Funded status (a)	$	(28,268	)	$	(4,132	)

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

(Thousands of Dollars)	2016			2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	78,359		$	49,226
Prior service credit	(27,695		)	(33,942		)
Total	$	50,664		$	15,284

(Thousands of Dollars)	2016		2015
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	$	50,664	$	15,284

Measurement date Dec. 31, 2016 Dec. 31, 2015

	2016		2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.13	%	4.65	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	5.50	%	6.00	%

Effective Jan. 1, 2017, the initial medical trend rate was decreased from 6.0 percent to 5.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is two 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	$	40,100	$	(34,155	)
Service and interest components	1,980		(1,677		)

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 $17.9 million, $18.3 million and $17.1 million during 2016, 2015 and 2014, respectively, of which $5.4 million, $5.6 million and $5.5 million were attributable to PSCo. Xcel Energy expects to contribute approximately $11.8 million during 2017, of which amounts attributable to PSCo will be zero.

Plan Amendments — In 2016 and 2015 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)	2016			2015			2014
Service cost	$	768		$	928		$	1,915
Interest cost	18,070			17,498			23,704
Expected return on plan assets	(22,299		)	(23,803		)	(30,214		)
Amortization of prior service credit	(6,247		)	(6,247		)	(6,247		)
Amortization of net loss	1,931			2,475			6,434
Net periodic postretirement benefit credit	$	(7,777	)	$	(9,149	)	$	(4,408	)

	2016		2015		2014
Significant Assumptions Used to Measure Costs:
Discount rate	4.65	%	4.08	%	4.82	%
Expected average long-term rate of return on assets	5.80		5.80		7.18

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
2017	$	79,506	$	33,912	$	2,140	$	31,772
2018	78,738		33,652		2,266		31,386
2019	80,914		33,467		2,383		31,084
2020	81,095		33,991		2,475		31,516
2021	82,084		33,588		2,574		31,014
2022-2026	417,876		156,773		14,246		142,527

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Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

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, 2016, accumulated other comprehensive losses related to interest rate derivatives included $1.0 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for 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, energy-related instruments and natural gas-related instruments, including derivatives.  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.

PSCo 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, 2016 and 2015.

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)	2016	2015
MWh of electricity	6,283	684
MMBtu of natural gas	42,203	12,515
Gallons of vehicle fuel	—	63

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

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

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, 2016, six of PSCo’s 10 most significant counterparties for these activities, comprising $8.8 million or 15 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  Four of the 10 most significant counterparties, comprising $21.1 million or 35 percent of this credit exposure at Dec. 31, 2016, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.  Seven 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)	2016			2015			2014
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,836	)	$	(23,878	)	$	(23,338	)
After-tax net unrealized (losses) related to derivatives accounted for as hedges	—			(30		)	(72		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	1,056			72			(468		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(22,780	)	$	(23,836	)	$	(23,878	)

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2016, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2016
	Pre-Tax Fair Value Gains 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 Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—	$	1,618	(a)	$	—		$	—
Vehicle fuel and other commodity	—		—		86		(b)	—			—
Total	$	—	$	—	$	1,704		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—	$	—		$	—		$	(257	)	(c)
Natural gas commodity	—		2,051		—			10,292		(d)	(5,832		)	(d)
Total	$	—	$	2,051	$	—		$	10,292		$	(6,089	)

	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		(d)	(7,620		)	(d)
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	)	(d)	$	(9,850	)	(d)
Total	$	—		$	451	$	—			$	(4,631	)		$	(9,850	)

^(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 for the year ended Dec. 31, 2016 and Dec. 31, 2015 included $0.2 million and $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 were immaterial.  The remaining settlement losses for the years ended Dec. 31, 2016, 2015 and 2014 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, 2016, 2015 and 2014.  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, 2016 and 2015, there were no derivative instruments in a liability position with underlying contract provisions that 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, 2016 and 2015.

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, 2016:

	Dec. 31, 2016
	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	$	1,124	$	5,453	$	—	$	6,577	$	(5,137	)	$	1,440
Natural gas commodity	—		7,778		—		7,778		—			7,778
Total current derivative assets	$	1,124	$	13,231	$	—	$	14,355	$	(5,137	)	9,218
PPAs (a)												1,716
Current derivative instruments												$	10,934
Noncurrent derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	1,652	$	—	$	1,652	$	—		$	1,652
Total noncurrent derivative assets	$	—	$	1,652	$	—	$	1,652	$	—		1,652
PPAs (a)												1,746
Noncurrent derivative instruments												$	3,398
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1,386	$	5,357	$	22	$	6,765	$	(5,137	)	$	1,628
Total current derivative liabilities	$	1,386	$	5,357	$	22	$	6,765	$	(5,137	)	1,628
PPAs (a)												5,160
Current derivative instruments												$	6,788
Noncurrent derivative liabilities
PPAs (a)												$	7,828
Noncurrent derivative instruments												$	7,828

^(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, 2016. At Dec. 31, 2016, 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, 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 on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015.  At Dec. 31, 2015, derivative assets and liabilities 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 immaterial losses recognized in earnings for level 3 commodity trading derivatives for the year ended Dec. 31, 2016. There were no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2015 and 2014.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2016, 2015 and 2014.

Fair Value of Long-Term Debt

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

	2016				2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,216,206	$	4,491,570	$	4,105,596	$	4,376,875

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU No. 2015-03.

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

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Other Income, Net

12 Months Ended

Dec. 31, 2016

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)	2016			2015			2014
Interest income	$	1,860		$	753		$	1,470
Other nonoperating income	2,241			2,408			3,601
Insurance policy expense	(281		)	(197		)	(806		)
Other nonoperating expense	(3		)	—			—
Other income, net	$	3,817		$	2,964		$	4,265

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Rate Matters

12 Months Ended

Dec. 31, 2016

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Pending Regulatory Proceedings — CPUC

Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. The 2016 earnings test did not result in a material customer refund obligation as of Dec. 31, 2016. PSCo will file its 2016 earnings test with the CPUC in April 2017. 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 400 GWh in 2015 and 2016 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 2017 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual spending limit of $84.3 million.

In February 2017, the CPUC approved PSCo’s 2017-2018 DSM plan:

• A 2017 DSM electric budget of $80.4 million and a natural gas budget of $13.1 million; and

• A 2018 DSM electric budget of $77.7 million and a natural gas budget of $12.8 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 $5.8 million and $5.5 million in 2016 and 2015, respectively. The cumulative credit to the RESA regulatory liability balance was $116.3 million and $110.6 million at Dec. 31, 2016 and Dec. 31, 2015, 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 Dec. 31, 2017.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

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:

Advanced Grid Intelligence and Security Initiative — PSCo is pursuing projects to update and advance its electric distribution grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over energy usage and implement new rate structures.

Rush Creek Wind Farm — PSCo has gained approval to build, own and operate a 600 MW wind generation facility and proposed transmission line in Colorado.

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 2017 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, 2016, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2017	$	241.2	$	293.6	$	117.8
2018	143.1		185.7		69.0
2019	68.6		179.7		37.1
2020	48.5		184.3		36.6
2021	49.6		191.5		34.4
Thereafter	293.4		171.2		609.9
Total	$	844.4	$	1,206.0	$	904.8

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 $44.0 million, $69.5 million and $69.5 million in 2016, 2015 and 2014, respectively. At Dec. 31, 2016, 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)
2017	$	24.3	$	4.4
2018	20.1		—
2019	11.5		—
2020	3.0		—
2021	3.0		—
Thereafter	16.4		—
Total	$	78.3	$	4.4

^(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 $127.0 million and $132.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2016 and 2015, 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 $8.1 million, $8.2 million, and $7.2 million for 2016, 2015 and 2014, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(65.3		)	(57.2		)
Total property held under capital leases, net	$	155.9		$	164.0

The remainder of the leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $118.2 million, $130.5 million and $126.2 million for 2016, 2015 and 2014, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $102.4 million, $113.5 million and $110.1 million in 2016, 2015 and 2014, 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
2017	$	11.0	$	96.3	$	107.3	$	25.7
2018	10.2		96.6		106.8		25.3
2019	10.3		97.5		107.8		25.1
2020	10.3		98.4		108.7		24.9
2021	9.7		99.4		109.1		23.8
Thereafter	45.2		483.7		528.9		462.7
Total minimum obligation							587.5
Interest component of obligation							(431.6		)
Present value of minimum obligation							$	155.9

^(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 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 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 1,571 MW and 1,802 MW of capacity under long-term PPAs as of Dec. 31, 2016, and 2015, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032.

Environmental Contingencies

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

Site Remediation— Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent 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 2017. PSCo had accrued $1.7 million for both of these sites at Dec. 31, 2016 and 2015, 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.

Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published a final rule regulating the management and disposal of coal combustion residuals (“CCR” or coal ash) as a nonhazardous waste. In December 2016, the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which includes provisions that allow the CCR rule to be implemented through a state or federal based permit program and that give the EPA direct enforcement authority.  PSCo is in the process of evaluating whether the costs of implementing the CCR rule under the potential federal and/or state permit programs could have a material impact on the results of operations, financial position or cash flows.

In 2015, industry and environmental non-governmental organizations sought judicial review of the final CCR rule. In June 2016, the D.C. Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. A final court decision is anticipated in the first half of 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on PSCo. PSCo believes that these associated costs would be recoverable through regulatory mechanisms.

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In 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 capital cost to comply with the 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 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. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule.  In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected by June 2017.

Air

GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, a final rule was published by the EPA for GHG emission standards for existing power plants.  Under the rule, states were required to develop implementation plans by September 2016, with the possibility of an extension to September 2018, or submit to a federal plan for the state prepared by the EPA.  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 was 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. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. During the pendency of the stay, states are not required to submit implementation plans and the EPA will not enforce deadlines or issue a federal plan for any state. Colorado is continuing formal planning efforts.

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 the state plan does not provide credit for the investments PSCo has already made to reduce GHG emissions, or if it requires additional initiatives or emission reductions, then its requirements would potentially impose additional substantial costs.  Until PSCo has more information about a SIP or the EPA finalizes its proposed federal plan 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 PSCo’s regulators do not allow recovery of 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.

Implementation of the NAAQS for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant. The Pawnee plant recently installed an SO₂ scrubber to reduce SO₂ emissions. In June 2016, the EPA issued final designations which found the area near the Pawnee plant is “unclassifiable.” It is anticipated that the area near the Pawnee plant will be able to show compliance with the NAAQS through air dispersion modeling performed by the Colorado Department of Public Health and Environment.

The areas near the remaining PSCo power plants, Comanche and Hayden, which utilize scrubbers to control SO₂ emissions, will be evaluated in the next designation phase, ending December 2017. In late 2016, PSCo submitted air dispersion modeling to the Colorado Department of Public Health and Environment and the EPA which demonstrated that PSCo’s Comanche and Hayden plants comply with the NAAQS. If an area is designated nonattainment in 2020, the states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. PSCo cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that should SO₂ control systems require upgrades for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

Revisions to the NAAQS for Ozone— In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard, however PSCo’s scheduled retirement of coal fired plants in Denver should help in any plan to mitigate non-attainment.

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, thermal 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 and radiation sources.

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, 2016 and 2015 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2016		Liabilities Recognized		Accretion		Cash Flow     Revisions (a)			Ending Balance      Dec. 31, 2016 (b)
Electric plant
Steam and other production asbestos	$	38,676	$	—	$	1,877	$	(103	)	$	40,450
Steam and other production ash containment	70,767		—		3,078		(1,245		)	72,600
Wind production	1,992		—		19		61			2,072
Electric distribution	1,130		—		45		6,494			7,669
Other	1,054		214		46		206			1,520
Natural gas plant
Gas transmission and distribution	122,168		—		5,009		33,542			160,719
Other	3,925		—		155		—			4,080
Common and other property
Common miscellaneous	796		—		28		(371		)	453
Total liability	$	240,508	$	214	$	10,257	$	38,584		$	289,563

^(a)  In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains.

^(b)  There were no ARO liabilities settled during the year ended Dec. 31, 2016.

(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.

Indeterminate AROs— 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, 2016. 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, 2016 and 2015 were $367 million and $364 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) alleged between $34 million to $50 million in sales with PSCo were 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, the FERC rejected 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 February 2016, the City appealed this decision to the Ninth Circuit.

In October 2016, a settlement was reached that resolved all outstanding claims between and among the City and the respondents, including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth Circuit. These terms have been met, bringing this matter to a close.

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC filed a notice of appeal. The matter has been fully briefed and plaintiff has requested oral arguments. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in Denver District Court in August 2016. DRC filed its brief in February 2017 and PSCo’s answer brief will be due March 2017.

PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and 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, 2016

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

13. Regulatory Assets and Liabilities

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

The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2016 and 2015 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2016				Dec. 31, 2015
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	27,270	$	568,258	$	29,260	$	497,973
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		151,022		—		144,953
Depreciation differences	1	Pending rate case	15,363		90,426		14,221		99,835
Net AROs (b)	1, 12	Plant lives	—		78,050		—		62,948
Purchased power contract costs	12	Term of related contract	1,035		29,029		1,319		29,143
Conservation programs (c)	1, 11	One to two years	9,262		6,986		8,466		6,947
Losses on reacquired debt	4	Term of related debt	1,203		6,120		1,421		6,957
Contract valuation adjustments (d)	10	Term of related contract	3,444		6,082		9,376		9,526
Gas pipeline inspection costs	12	Two years	—		4,405		3,611		—
Property tax		Various	9,393		1,653		21,558		14,428
CACJA recovery rider		Less than one year	24,260		—		—		20,020
Other		Various	12,553		16,398		2,840		13,545
Total regulatory assets			$	103,783	$	958,429	$	92,072	$	906,275

^(a)  Includes $4.2 million and $4.4 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2016 and 2015, respectively.

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

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

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

The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2016 and 2015 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2016				Dec. 31, 2015
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	367,440	$	—	$	364,291
Renewable resources and environmental initiatives	11, 12	Various	3,600		67,728		3,311		40,988
Investment tax credit deferrals	1, 7	Various	—		18,797		—		20,515
Deferred income tax adjustment	1	Various	—		16,260		—		16,891
Gain from asset sales		Pending rate case	—		1,469		—		—
PSCo earnings test	11	One to two years	8,300		914		42,868		9,472
Deferred electric, natural gas and steam production costs	1	Less than one year	35,123		—		66,696		—
Conservation programs (a)	1, 11	Less than one year	24,077		—		33,460		—
Gas pipeline inspection costs	12	Less than one year	5,108		—		1,140		4,273
Low income discount program		Less than one year	881		—		1,393		—
Other		Various	24,021		40,325		3,955		14,991
Total regulatory liabilities (b)			$	101,110	$	512,933	$	152,823	$	471,421

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

^(b)  Revenue subject to refund of $2.4 million and $9.1 million for 2016 and 2015, respectively, is included in other current liabilities.

At Dec. 31, 2016 and 2015, approximately $28 million and $54 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, 2016

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

14. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2016 and 2015 were as follows:

	Year Ended Dec. 31, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(23,836	)	$	—		$	(23,836	)
Other comprehensive loss before reclassifications	—			(223		)	(223		)
Losses reclassified from net accumulated other comprehensive loss	1,056			3			1,059
Net current period other comprehensive income (loss)	1,056			(220		)	836
Accumulated other comprehensive loss at Dec. 31	$	(22,780	)	$	(220	)	$	(23,000	)

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

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2016				Year Ended Dec. 31, 2015
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	1,618		(a)	$	54		(a)
Vehicle fuel derivatives	86			(b)	57			(b)
Total, pre-tax	1,704				111
Tax benefit	(648		)		(39		)
Total, net of tax	1,056				72
Defined benefit pension and postretirement losses (gains):
Amortization of net losses	5			(c)	—
Total, pre-tax	5				—
Tax benefit	(2		)		—
Total, net of tax	3				—
Total amounts reclassified, net of tax	$	1,059			$	72

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

^(c)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans.

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Segments and Related Information

12 Months Ended

Dec. 31, 2016

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
2016
Operating revenues (a)	$	3,049,352	$	957,721	$	40,723		$	—		$	4,047,796
Intersegment revenues	275		110		—			(385		)	—
Total revenues	$	3,049,627	$	957,831	$	40,723		$	(385	)	$	4,047,796
Depreciation and amortization	$	337,583	$	101,663	$	4,309		$	—		$	443,555
Interest charges and financing costs	136,274		37,881		431			—			174,586
Income tax expense (benefit)	228,825		45,960		(867		)	—			273,918
Net income	383,973		75,426		4,092			—			463,491

(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

^(a)  Operating revenues include $13 million, $13 million and $14 million of intercompany revenue for the years ended Dec. 31, 2016, 2015 and 2014, 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, 2016

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)	2016		2015		2014
Operating revenues:
Electric	$	8,809	$	8,632	$	9,614
Other	4,525		4,441		4,441
Operating expenses:
Purchased power	56		—		23
Other operating expenses — paid to Xcel Energy Services Inc.	446,086		414,620		454,250
Interest expense	149		211		158
Interest income	—		45		61

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

	2016				2015
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	7,669	$	—	$	4,419	$	—
NSP-Wisconsin	974		—		71		—
SPS	745		—		414		—
Other subsidiaries of Xcel Energy Inc.	33		98,797		5		76,643
	$	9,421	$	98,797	$	4,909	$	76,643

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2016		June 30, 2016		Sept. 30, 2016		Dec. 31, 2016
Operating revenues	$	1,057,841	$	909,852	$	1,059,177	$	1,020,926
Operating income	223,190		180,629		315,605		170,197
Net income	115,874		87,344		173,607		86,666

	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

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Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2016

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, 2016, 2015 AND 2014

(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:
2016	$	20,122	$	14,121	$	4,447	$	19,078	$	19,612
2015	23,122		13,052		5,175		21,227		20,122
2014	22,505		17,005		6,240		22,628		23,122

^(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, 2016

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 C&I 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 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 2.6, 2.7 and 2.7 percent for the years ended Dec. 31, 2016, 2015 and 2014, 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 tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.

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

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

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

See Note 7 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments

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

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and 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 NAVs.  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, 2016 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, 2016

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	324,512		$	321,004
Less allowance for bad debts	(19,612		)	(20,122		)
	$	304,900		$	300,882

Inventories

(Thousands of Dollars)	Dec. 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	66,161	$	58,128
Fuel	66,429		78,586
Natural gas	69,630		68,848
	$	202,220	$	205,562

Property, Plant and Equipment, Net

(Thousands of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	12,304,436		$	11,856,126
Natural gas plant	3,710,772			3,420,249
Common and other property	919,955			862,840
Plant to be retired (a)	31,839			38,249
Construction work in progress	484,340			408,963
Total property, plant and equipment	17,451,342			16,586,427
Less accumulated depreciation	(4,601,543		)	(4,414,216		)
	$	12,849,799		$	12,172,211

^(a)  In 2017, PSCo expects to early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired by approximately 2025.  Amounts are presented net of accumulated depreciation.

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Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2016

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At Dec. 31, 2016, PSCo had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	700	$	132	$	568

^(a)  This credit facility matures in June 2021.

^(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, 2016
Borrowing limit	$	250
Amount outstanding at period end	—
Average amount outstanding	56
Maximum amount outstanding	141
Weighted average interest rate, computed on a daily basis	0.78		%
Weighted average interest rate at period end	N/A

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	21			1			4
Maximum amount outstanding	141			34			97
Weighted average interest rate, computed on a daily basis	0.73		%	0.41		%	0.25		%
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, 2016
Borrowing limit	$	700
Amount outstanding at period end	129
Average amount outstanding	33
Maximum amount outstanding	151
Weighted average interest rate, computed on a daily basis	0.78		%
Weighted average interest rate at period end	0.95

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	129			14			382
Average amount outstanding	24			95			167
Maximum amount outstanding	154			449			393
Weighted average interest rate, computed on a daily basis	0.70		%	0.51		%	0.31		%
Weighted average interest rate at period end	0.95			0.60			0.65

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016

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, 2016:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	149,221	$	67,415	$	97	76	%
Hayden Unit 2	148,795		64,024		64		37
Hayden Common Facilities	38,230		18,951		282		53
Craig Units 1 and 2	60,318		37,570		15,730		10
Craig Common Facilities 1, 2 and 3	37,925		19,312		183		7
Comanche Unit 3	892,978		112,254		6		67
Comanche Common Facilities	24,694		1,821		636		82
Electric Transmission:
Transmission and other facilities, including substations	166,840		65,619		4,313		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	23,406		7,679		—		60
Gas Transportation Compressor	8,397		368		—		50
Total	$	1,550,804	$	395,013	$	21,311

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	Dec. 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.9	$	2.4
Unrecognized tax benefit — Temporary tax positions	16.8		15.0
Total unrecognized tax benefit	$	19.7	$	17.4

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

(Millions of Dollars)	2016			2015			2014
Balance at Jan. 1	$	17.4		$	11.9		$	8.4
Additions based on tax positions related to the current year	2.7			4.5			3.7
Reductions based on tax positions related to the current year	—			(1.5		)	(0.7		)
Additions for tax positions of prior years	0.5			2.5			2.8
Reductions for tax positions of prior years	(0.9		)	—			(1.2		)
Settlements with taxing authorities	—			—			(1.1		)
Balance at Dec. 31	$	19.7		$	17.4		$	11.9

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, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.8	)	$	(4.3	)

Interest Payable related to Unrecognized Tax Benefits [Table Text Block]

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)	2016			2015			2014
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.4	)	$	(0.2	)	$	(0.1	)
Interest expense related to unrecognized tax benefits	(0.7		)	(0.2		)	(0.1		)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(1.1	)	$	(0.4	)	$	(0.2	)

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)	2016			2015
Federal NOL carryforward	$	260		$	328
Federal tax credit carryforwards	25			24
State NOL carryforwards	684			684
State tax credit carryforwards, net of federal detriment (a)	13			13
Valuation allowances for state credit carryforwards, net of federal detriment (b)	(3		)	(1		)

^(a)  State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2016 and 2015, respectively.

^(b)  Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $1 million as of Dec. 31, 2016 and 2015, respectively.

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:

	2016		2015		2014
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		3.2		2.8
Tax credits recognized, net of federal income tax expense	(0.7	)	(0.7	)	(0.8	)
Regulatory differences — utility plant items	(0.5	)	(0.3	)	(2.1	)
Change in unrecognized tax benefits (expense)	—		0.1		(0.1	)
Other, net	0.1		0.1		0.1
Effective income tax rate	37.1	%	37.4	%	34.9	%

Schedule of Components of Income Tax Expense (Benefit)

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

(Thousands of Dollars)	2016			2015			2014
Current federal tax expense (benefit)	$	45,287		$	(1,166	)	$	9,550
Current state tax expense (benefit)	8,754			(727		)	2,611
Current change in unrecognized tax expense	680			5,244			6,548
Deferred federal tax expense	195,064			246,096			208,781
Deferred state tax expense	27,216			36,450			26,196
Deferred change in unrecognized tax benefit	(278		)	(4,650		)	(7,154		)
Deferred investment tax credits	(2,805		)	(2,807		)	(2,941		)
Total income tax expense	$	273,918		$	278,440		$	243,591

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

(Thousands of Dollars)	2016			2015			2014
Deferred tax expense excluding items below	$	230,931		$	285,144		$	254,142
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(8,418		)	(7,229		)	(26,649		)
Tax (expense) benefit allocated to other comprehensive income and other	(511		)	(19		)	330
Deferred tax expense	$	222,002		$	277,896		$	227,823

Schedule of Deferred Tax Assets and Liabilities

The components of the net deferred tax liability at Dec. 31 were as follows:

(Thousands of Dollars)	2016		2015
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,967,162	$	2,772,043
Employee benefits	87,693		105,049
Other	69,931		82,732
Total deferred tax liabilities	$	3,124,786	$	2,959,824
Deferred tax assets:
NOL carryforward	$	115,328	$	147,763
Tax credit carryforward	34,658		35,240
Regulatory liabilities	19,635		17,201
Deferred investment tax credits	11,653		12,718
Deferred fuel costs	10,070		29,694
Rate refund	7,221		23,352
Other	37,092		35,658
Total deferred tax assets	$	235,657	$	301,626
Net deferred tax liability	$	2,889,129	$	2,658,198

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Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2016

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
2017	$	79,506	$	33,912	$	2,140	$	31,772
2018	78,738		33,652		2,266		31,386
2019	80,914		33,467		2,383		31,084
2020	81,095		33,991		2,475		31,516
2021	82,084		33,588		2,574		31,014
2022-2026	417,876		156,773		14,246		142,527

Pension Plans

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

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

	2016		2015
Domestic and international equity securities	36	%	36	%
Long-duration fixed income and interest rate swap securities	31		32
Short-to-intermediate fixed income securities	15		12
Alternative investments	16		18
Cash	2		2
Total	100	%	100	%

The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2016 and 2015:

	Dec. 31, 2016
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	34,957	$	—		$	—	$	—	$	34,957
Commingled funds:
U.S. equity funds	—		—			—		165,621		165,621
Non U.S. equity funds	—		—			—		122,197		122,197
U.S. corporate bond funds	—		—			—		96,995		96,995
Emerging market equity funds	—		—			—		64,784		64,784
Emerging market debt funds	—		—			—		53,703		53,703
Commodity funds	—		—			—		7,497		7,497
Private equity investments	—		—			—		31,828		31,828
Real estate	—		—			—		61,048		61,048
Other commingled funds	—		—			—		74,696		74,696
Debt securities:
Government securities	—		168,014			—		—		168,014
U.S. corporate bonds	—		86,081			—		—		86,081
Non U.S. corporate bonds	—		13,828			—		—		13,828
Mortgage-backed securities	—		2,179			—		—		2,179
Asset-backed securities	—		1,032			—		—		1,032
Equity securities:
U.S. equities	27,348		—			—		—		27,348
Other	—		(7,595		)	—		—		(7,595		)
Total	$	62,305	$	263,539		$	—	$	678,369	$	1,004,213

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	81,954	$	—		$	—	$	—	$	81,954
Derivatives	—		1,204			—		—		1,204
Commingled funds:
U.S. equity funds	—		—			—		125,011		125,011
Non U.S. equity funds	—		—			—		119,394		119,394
U.S. corporate bond funds	—		—			—		82,827		82,827
Emerging market equity funds	—		—			—		56,525		56,525
Emerging market debt funds	—		—			—		54,362		54,362
Commodity funds	—		—			—		14,169		14,169
Private equity investments	—		—			—		34,353		34,353
Real estate	—		—			—		67,075		67,075
Other commingled funds	—		—			—		72,327		72,327
Debt securities:
Government securities	—		214,341			—		—		214,341
U.S. corporate bonds	—		74,787			—		—		74,787
Non U.S. corporate bonds	—		12,127			—		—		12,127
Asset-backed securities	—		881			—		—		881
Equity securities:
U.S. equities	28,797		—			—		—		28,797
Other	—		(3,453		)	—		—		(3,453		)
Total	$	110,751	$	299,887		$	—	$	626,043	$	1,036,681

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)	2016			2015
Accumulated Benefit Obligation at Dec. 31	$	1,213,890		$	1,192,798
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,224,650		$	1,277,957
Service cost	25,926			28,260
Interest cost	55,405			50,857
Transfer to other plan	(9,149		)	(2,938		)
Plan amendments	206			—
Actuarial loss (gain)	51,779			(54,737		)
Benefit payments	(96,995		)	(74,749		)
Obligation at Dec. 31	$	1,251,822		$	1,224,650

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2016			2015
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,036,681		$	1,103,865
Actual return (loss) on plan assets	56,762			(9,122		)
Employer contributions	16,829			20,056
Transfer to other plan	(9,064		)	(3,369		)
Benefit payments	(96,995		)	(74,749		)
Fair value of plan assets at Dec. 31	$	1,004,213		$	1,036,681

Funded Status of Plans

(Thousands of Dollars)	2016			2015
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(247,609	)	$	(187,969	)

^(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)	2016			2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	554,999		$	521,703
Prior service credit	(12,155		)	(15,572		)
Total	$	542,844		$	506,131

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)	2016		2015
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	$	515,708	$	28,852
Noncurrent regulatory assets	26,853		477,279
Deferred income taxes	108		—
Net-of-tax accumulated OCI	175		—
Total	$	542,844	$	506,131

Schedule of Assumptions Used

Measurement date Dec. 31, 2016 Dec. 31, 2015

	2016		2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.13	%	4.66	%
Expected average long-term increase in compensation level	3.75		4.00
Mortality table	RP-2014		RP-2014

	2016		2015		2014
Significant Assumptions Used to Measure Costs:
Discount rate	4.66	%	4.11	%	4.75	%
Expected average long-term increase in compensation level	4.00		3.75		3.75
Expected average long-term rate of return on assets	6.84		6.81		6.81

Components of Net Periodic Benefit Costs

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

(Thousands of Dollars)	2016			2015			2014
Service cost	$	25,926		$	28,260		$	23,939
Interest cost	55,405			50,857			53,277
Expected return on plan assets	(70,769		)	(72,590		)	(70,709		)
Amortization of prior service credit	(3,211		)	(3,136		)	(3,092		)
Amortization of net loss	26,771			36,377			33,892
Net periodic pension cost	34,122			39,768			37,307
Credits (costs) not recognized due to effects of regulation	3,364			(1,464		)	—
Net benefit cost recognized for financial reporting	$	37,486		$	38,304		$	37,307

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, 2016 and 2015:

	Dec. 31, 2016
(Thousands of Dollars)	Level 1		Level 2		Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	18,288	$	—	$	—	$	—	$	18,288
Insurance contracts	—		42,046		—		—		42,046
Commingled funds:
U.S. equity funds	—		—		—		48,462		48,462
U.S fixed income funds	—		—		—		24,132		24,132
Emerging market debt funds	—		—		—		27,089		27,089
Other commingled funds	—		—		—		48,922		48,922
Debt securities:
Government securities	—		33,600		—		—		33,600
U.S. corporate bonds	—		55,473		—		—		55,473
Non U.S. corporate bonds	—		15,384		—		—		15,384
Asset-backed securities	—		16,845		—		—		16,845
Mortgage-backed securities	—		25,563		—		—		25,563
Equity securities:
Non U.S. equities	36,462		—		—		—		36,462
Other	—		1,289		—		—		1,289
Total	$	54,750	$	190,200	$	—	$	148,605	$	393,555

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2			Level 3		Investments Measured at NAV (a)		Total
Cash equivalents	$	17,524	$	—		$	—	$	—	$	17,524
Insurance contracts	—		42,123			—		—		42,123
Commingled funds:
U.S. equity funds	—		—			—		34,089		34,089
Non U.S. equity funds	—		—			—		29,979		29,979
U.S fixed income funds	—		—			—		21,638		21,638
Emerging market equity funds	—		—			—		9,901		9,901
Emerging market debt funds	—		—			—		31,827		31,827
Other commingled funds	—		—			—		55,302		55,302
Debt securities:
Government securities	—		35,016			—		—		35,016
U.S. corporate bonds	—		53,433			—		—		53,433
Non U.S. corporate bonds	—		11,598			—		—		11,598
Asset-backed securities	—		25,602			—		—		25,602
Mortgage-backed securities	—		31,778			—		—		31,778
Other	—		(368		)	—		—		(368		)
Total	$	17,524	$	199,182		$	—	$	182,736	$	399,442

^(a)  Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

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

	2016		2015
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	%

Change in Projected Benefit Obligation

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

(Thousands of Dollars)	2016			2015
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	403,574		$	443,753
Service cost	768			928
Interest cost	18,070			17,498
Medicare subsidy reimbursements	1,901			1,712
Plan participants’ contributions	5,376			4,961
Actuarial loss (gain)	27,355			(32,001		)
Benefit payments	(35,221		)	(33,277		)
Obligation at Dec. 31	$	421,823		$	403,574

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2016			2015
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	399,442		$	425,282
Actual return (loss) on plan assets	18,590			(3,076		)
Plan participants’ contributions	5,376			4,961
Employer contributions	5,368			5,552
Benefit payments	(35,221		)	(33,277		)
Fair value of plan assets at Dec. 31	$	393,555		$	399,442

Funded Status of Plans

(Thousands of Dollars)	2016			2015
Funded Status at Dec. 31:
Funded status (a)	$	(28,268	)	$	(4,132	)

^(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)	2016			2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	78,359		$	49,226
Prior service credit	(27,695		)	(33,942		)
Total	$	50,664		$	15,284

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)	2016		2015
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	$	50,664	$	15,284

Schedule of Assumptions Used

Measurement date Dec. 31, 2016 Dec. 31, 2015

	2016		2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.13	%	4.65	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	5.50	%	6.00	%

	2016		2015		2014
Significant Assumptions Used to Measure Costs:
Discount rate	4.65	%	4.08	%	4.82	%
Expected average long-term rate of return on assets	5.80		5.80		7.18

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	$	40,100	$	(34,155	)
Service and interest components	1,980		(1,677		)

Components of Net Periodic Benefit Costs

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

(Thousands of Dollars)	2016			2015			2014
Service cost	$	768		$	928		$	1,915
Interest cost	18,070			17,498			23,704
Expected return on plan assets	(22,299		)	(23,803		)	(30,214		)
Amortization of prior service credit	(6,247		)	(6,247		)	(6,247		)
Amortization of net loss	1,931			2,475			6,434
Net periodic postretirement benefit credit	$	(7,777	)	$	(9,149	)	$	(4,408	)

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Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

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

(Amounts in Thousands)(a)(b)	2016	2015
MWh of electricity	6,283	684
MMBtu of natural gas	42,203	12,515
Gallons of vehicle fuel	—	63

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

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

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)	2016			2015			2014
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23,836	)	$	(23,878	)	$	(23,338	)
After-tax net unrealized (losses) related to derivatives accounted for as hedges	—			(30		)	(72		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	1,056			72			(468		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(22,780	)	$	(23,836	)	$	(23,878	)

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, 2016, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2016
	Pre-Tax Fair Value Gains 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 Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—	$	1,618	(a)	$	—		$	—
Vehicle fuel and other commodity	—		—		86		(b)	—			—
Total	$	—	$	—	$	1,704		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—	$	—		$	—		$	(257	)	(c)
Natural gas commodity	—		2,051		—			10,292		(d)	(5,832		)	(d)
Total	$	—	$	2,051	$	—		$	10,292		$	(6,089	)

	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		(d)	(7,620		)	(d)
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	)	(d)	$	(9,850	)	(d)
Total	$	—		$	451	$	—			$	(4,631	)		$	(9,850	)

^(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 for the year ended Dec. 31, 2016 and Dec. 31, 2015 included $0.2 million and $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 were immaterial.  The remaining settlement losses for the years ended Dec. 31, 2016, 2015 and 2014 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, 2016:

	Dec. 31, 2016
	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	$	1,124	$	5,453	$	—	$	6,577	$	(5,137	)	$	1,440
Natural gas commodity	—		7,778		—		7,778		—			7,778
Total current derivative assets	$	1,124	$	13,231	$	—	$	14,355	$	(5,137	)	9,218
PPAs (a)												1,716
Current derivative instruments												$	10,934
Noncurrent derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	1,652	$	—	$	1,652	$	—		$	1,652
Total noncurrent derivative assets	$	—	$	1,652	$	—	$	1,652	$	—		1,652
PPAs (a)												1,746
Noncurrent derivative instruments												$	3,398
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1,386	$	5,357	$	22	$	6,765	$	(5,137	)	$	1,628
Total current derivative liabilities	$	1,386	$	5,357	$	22	$	6,765	$	(5,137	)	1,628
PPAs (a)												5,160
Current derivative instruments												$	6,788
Noncurrent derivative liabilities
PPAs (a)												$	7,828
Noncurrent derivative instruments												$	7,828

^(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, 2016. At Dec. 31, 2016, 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, 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 on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015.  At Dec. 31, 2015, derivative assets and liabilities 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, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2016				2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	4,216,206	$	4,491,570	$	4,105,596	$	4,376,875

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Other Income, Net (Tables)

12 Months Ended

Dec. 31, 2016

Other Income and Expenses [Abstract]

Other Income, Net

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

(Thousands of Dollars)	2016			2015			2014
Interest income	$	1,860		$	753		$	1,470
Other nonoperating income	2,241			2,408			3,601
Insurance policy expense	(281		)	(197		)	(806		)
Other nonoperating expense	(3		)	—			—
Other income, net	$	3,817		$	2,964		$	4,265

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Estimated Minimum Purchases Under Fuel Contracts

The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2016, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2017	$	241.2	$	293.6	$	117.8
2018	143.1		185.7		69.0
2019	68.6		179.7		37.1
2020	48.5		184.3		36.6
2021	49.6		191.5		34.4
Thereafter	293.4		171.2		609.9
Total	$	844.4	$	1,206.0	$	904.8

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

At Dec. 31, 2016, 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)
2017	$	24.3	$	4.4
2018	20.1		—
2019	11.5		—
2020	3.0		—
2021	3.0		—
Thereafter	16.4		—
Total	$	78.3	$	4.4

^(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 $8.1 million, $8.2 million, and $7.2 million for 2016, 2015 and 2014, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(65.3		)	(57.2		)
Total property held under capital leases, net	$	155.9		$	164.0

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
2017	$	11.0	$	96.3	$	107.3	$	25.7
2018	10.2		96.6		106.8		25.3
2019	10.3		97.5		107.8		25.1
2020	10.3		98.4		108.7		24.9
2021	9.7		99.4		109.1		23.8
Thereafter	45.2		483.7		528.9		462.7
Total minimum obligation							587.5
Interest component of obligation							(431.6		)
Present value of minimum obligation							$	155.9

^(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, 2016 and 2015 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2016		Liabilities Recognized		Accretion		Cash Flow     Revisions (a)			Ending Balance      Dec. 31, 2016 (b)
Electric plant
Steam and other production asbestos	$	38,676	$	—	$	1,877	$	(103	)	$	40,450
Steam and other production ash containment	70,767		—		3,078		(1,245		)	72,600
Wind production	1,992		—		19		61			2,072
Electric distribution	1,130		—		45		6,494			7,669
Other	1,054		214		46		206			1,520
Natural gas plant
Gas transmission and distribution	122,168		—		5,009		33,542			160,719
Other	3,925		—		155		—			4,080
Common and other property
Common miscellaneous	796		—		28		(371		)	453
Total liability	$	240,508	$	214	$	10,257	$	38,584		$	289,563

^(a)  In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains.

^(b)  There were no ARO liabilities settled during the year ended Dec. 31, 2016.

(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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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2016 and 2015 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2016				Dec. 31, 2015
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	27,270	$	568,258	$	29,260	$	497,973
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		151,022		—		144,953
Depreciation differences	1	Pending rate case	15,363		90,426		14,221		99,835
Net AROs (b)	1, 12	Plant lives	—		78,050		—		62,948
Purchased power contract costs	12	Term of related contract	1,035		29,029		1,319		29,143
Conservation programs (c)	1, 11	One to two years	9,262		6,986		8,466		6,947
Losses on reacquired debt	4	Term of related debt	1,203		6,120		1,421		6,957
Contract valuation adjustments (d)	10	Term of related contract	3,444		6,082		9,376		9,526
Gas pipeline inspection costs	12	Two years	—		4,405		3,611		—
Property tax		Various	9,393		1,653		21,558		14,428
CACJA recovery rider		Less than one year	24,260		—		—		20,020
Other		Various	12,553		16,398		2,840		13,545
Total regulatory assets			$	103,783	$	958,429	$	92,072	$	906,275

^(a)  Includes $4.2 million and $4.4 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2016 and 2015, respectively.

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

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

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

Regulatory Liabilities

The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2016 and 2015 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2016				Dec. 31, 2015
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	367,440	$	—	$	364,291
Renewable resources and environmental initiatives	11, 12	Various	3,600		67,728		3,311		40,988
Investment tax credit deferrals	1, 7	Various	—		18,797		—		20,515
Deferred income tax adjustment	1	Various	—		16,260		—		16,891
Gain from asset sales		Pending rate case	—		1,469		—		—
PSCo earnings test	11	One to two years	8,300		914		42,868		9,472
Deferred electric, natural gas and steam production costs	1	Less than one year	35,123		—		66,696		—
Conservation programs (a)	1, 11	Less than one year	24,077		—		33,460		—
Gas pipeline inspection costs	12	Less than one year	5,108		—		1,140		4,273
Low income discount program		Less than one year	881		—		1,393		—
Other		Various	24,021		40,325		3,955		14,991
Total regulatory liabilities (b)			$	101,110	$	512,933	$	152,823	$	471,421

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

^(b)  Revenue subject to refund of $2.4 million and $9.1 million for 2016 and 2015, respectively, is included in other current liabilities.

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Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015 were as follows:

	Year Ended Dec. 31, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(23,836	)	$	—		$	(23,836	)
Other comprehensive loss before reclassifications	—			(223		)	(223		)
Losses reclassified from net accumulated other comprehensive loss	1,056			3			1,059
Net current period other comprehensive income (loss)	1,056			(220		)	836
Accumulated other comprehensive loss at Dec. 31	$	(22,780	)	$	(220	)	$	(23,000	)

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

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2016				Year Ended Dec. 31, 2015
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	1,618		(a)	$	54		(a)
Vehicle fuel derivatives	86			(b)	57			(b)
Total, pre-tax	1,704				111
Tax benefit	(648		)		(39		)
Total, net of tax	1,056				72
Defined benefit pension and postretirement losses (gains):
Amortization of net losses	5			(c)	—
Total, pre-tax	5				—
Tax benefit	(2		)		—
Total, net of tax	3				—
Total amounts reclassified, net of tax	$	1,059			$	72

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

^(c)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans.

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Results from Operations by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2016
Operating revenues (a)	$	3,049,352	$	957,721	$	40,723		$	—		$	4,047,796
Intersegment revenues	275		110		—			(385		)	—
Total revenues	$	3,049,627	$	957,831	$	40,723		$	(385	)	$	4,047,796
Depreciation and amortization	$	337,583	$	101,663	$	4,309		$	—		$	443,555
Interest charges and financing costs	136,274		37,881		431			—			174,586
Income tax expense (benefit)	228,825		45,960		(867		)	—			273,918
Net income	383,973		75,426		4,092			—			463,491

(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

^(a)  Operating revenues include $13 million, $13 million and $14 million of intercompany revenue for the years ended Dec. 31, 2016, 2015 and 2014, 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, 2016

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)	2016		2015		2014
Operating revenues:
Electric	$	8,809	$	8,632	$	9,614
Other	4,525		4,441		4,441
Operating expenses:
Purchased power	56		—		23
Other operating expenses — paid to Xcel Energy Services Inc.	446,086		414,620		454,250
Interest expense	149		211		158
Interest income	—		45		61

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

	2016				2015
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	7,669	$	—	$	4,419	$	—
NSP-Wisconsin	974		—		71		—
SPS	745		—		414		—
Other subsidiaries of Xcel Energy Inc.	33		98,797		5		76,643
	$	9,421	$	98,797	$	4,909	$	76,643

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2016		June 30, 2016		Sept. 30, 2016		Dec. 31, 2016
Operating revenues	$	1,057,841	$	909,852	$	1,059,177	$	1,020,926
Operating income	223,190		180,629		315,605		170,197
Net income	115,874		87,344		173,607		86,666

	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

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	2.60%	2.70%	2.70%
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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Accounting Pronouncements Adoption of New Accounting Pronouncements (Details) $ in Millions	Dec. 31, 2015 USD ($)
Accounting Standards Update 2015-03 | Long-term Debt
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of deferred debt issuance costs, net	$ 26.6
Accounting Standards Update 2015-03 | Other Noncurrent Assets
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of deferred debt issuance costs, net	(26.6)
Accounting Standards Update 2015-17
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred Income Tax Liabilities, Net	$ 62.7

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Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$ 324,512	$ 321,004
Less allowance for bad debts	(19,612)	(20,122)
Accounts receivable, net	$ 304,900	$ 300,882

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Inventories	$ 202,220	$ 205,562
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	66,161	58,128
Fuel
Public Utilities, Inventory [Line Items]
Inventories	66,429	78,586
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 69,630	$ 68,848

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 17,451,342	$ 16,586,427
Less accumulated depreciation		(4,601,543)	(4,414,216)
Property, plant and equipment, net		12,849,799	12,172,211
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		12,304,436	11,856,126
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		3,710,772	3,420,249
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		919,955	862,840
Plant to be retired
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	[1]	31,839	38,249
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 484,340	$ 408,963

[1] In 2017, PSCo expects to early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired by approximately 2025. 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, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Amount outstanding at period end	$ 129,000	$ 129,000	$ 14,000
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	56,000	21,000	1,000	4,000
Maximum amount outstanding	$ 141,000	$ 141,000	$ 34,000	$ 97,000
Weighted average interest rate, computed on a daily basis (percentage)	0.78%	0.73%	0.41%	0.25%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 700,000	$ 700,000	$ 700,000	$ 700,000
Amount outstanding at period end	129,000	129,000	14,000	382,000
Average amount outstanding	33,000	24,000	95,000	167,000
Maximum amount outstanding	$ 151,000	$ 154,000	$ 449,000	$ 393,000
Weighted average interest rate, computed on a daily basis (percentage)	0.78%	0.70%	0.51%	0.31%
Weighted average interest rate at period end (percentage)	0.95%	0.95%	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, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 129,000	$ 14,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 3,000	$ 4,000
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)		12 Months Ended
		Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Line of Credit Facility [Line Items]
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 Debt To Total Capitalization Ratio (as a percent)		45.00%	45.00%
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
Credit Facility
Line of Credit Facility [Line Items]
Credit facility	[1]	700,000,000
Drawn	[2]	132,000,000
Available		568,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0
PSCo | Credit Facility
Line of Credit Facility [Line Items]
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

[1] This credit facility matures in June 2021.

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

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) - Credit Facility	12 Months Ended
	Dec. 31, 2016 USD ($)
Line of Credit Facility [Line Items]
Borrowing limit	$ 700,000,000	[1]
PSCo
Line of Credit Facility [Line Items]
Debt Instrument, Term	5 years
PSCo | Original Terms and Conditions [Member]
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%
Maturity Date	Oct. 31, 2019
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%
PSCo | Amended Terms and Conditions [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.75%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.50%
Maturity Date	Jun. 30, 2021
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.06%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.225%

[1] This credit facility matures in June 2021.

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Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net	$ 26.8	$ 26.6
First Mortgage Bonds | Series Due June 15, 2046 [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage (in hundredths)	3.55%
Maturity date	Jun. 15, 2046
First Mortgage Bonds | Series Due May 15, 2025
Debt Instrument [Line Items]
Interest rate, stated percentage (in hundredths)	2.90%
Maturity date	May 15, 2025
First Mortgage Bonds | Series Due Aug. 1, 2018
Debt Instrument [Line Items]
Interest rate, stated percentage (in hundredths)	5.80%	5.80%
Maturity date	Aug. 01, 2018	Aug. 01, 2018
Long-term Debt, Maturities, Repayments of Principal in Year Two	$ 300.0
First Mortgage Bonds | Series Due June 1, 2019
Debt Instrument [Line Items]
Interest rate, stated percentage (in hundredths)	5.125%	5.125%
Maturity date	Jun. 01, 2019	Jun. 01, 2019
Long-term Debt, Maturities, Repayments of Principal in Year Three	$ 400.0
First Mortgage Bonds | Series Due Nov. 15, 2020
Debt Instrument [Line Items]
Interest rate, stated percentage (in hundredths)	3.20%	3.20%
Maturity date	Nov. 15, 2020	Nov. 15, 2020
Long-term Debt, Maturities, Repayments of Principal in Year Four	$ 400.0
PSCo | First Mortgage Bonds | Series Due June 15, 2046 [Member]
Debt Instrument [Line Items]
Face amount	$ 250.0
Interest rate, stated percentage (in hundredths)	3.55%
Maturity date	Jun. 15, 2046
PSCo | First Mortgage Bonds | Series Due May 15, 2025
Debt Instrument [Line Items]
Face amount		$ 250.0
Interest rate, stated percentage (in hundredths)		2.90%
Maturity date		May 15, 2025

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Preferred Stock (Details)	Dec. 31, 2016 $ / 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, 2016 USD ($) MW
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 1,550,804
Accumulated depreciation	395,013
Construction work in progress	$ 21,311
Generating capacity (in MW) | MW	816
Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 149,221
Accumulated depreciation	67,415
Construction work in progress	$ 97
Ownership percentage (in hundredths)	76.00%
Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 148,795
Accumulated depreciation	64,024
Construction work in progress	$ 64
Ownership percentage (in hundredths)	37.00%
Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 38,230
Accumulated depreciation	18,951
Construction work in progress	$ 282
Ownership percentage (in hundredths)	53.00%
Electric Generation | Craig Units 1 and 2
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 60,318
Accumulated depreciation	37,570
Construction work in progress	$ 15,730
Ownership percentage (in hundredths)	10.00%
Electric Generation | Craig Common Facilities 1, 2 and 3
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 37,925
Accumulated depreciation	19,312
Construction work in progress	$ 183
Ownership percentage (in hundredths)	7.00%
Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 892,978
Accumulated depreciation	112,254
Construction work in progress	$ 6
Ownership percentage (in hundredths)	67.00%
Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 24,694
Accumulated depreciation	1,821
Construction work in progress	$ 636
Ownership percentage (in hundredths)	82.00%
Electric Transmission | Transmission and other facilities, including substations
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 166,840
Accumulated depreciation	65,619
Construction work in progress	$ 4,313
Ownership percentage of group of jointly owned facilities	Various
Gas Transportation | Rifle to Avon
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 23,406
Accumulated depreciation	7,679
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	$ 8,397
Accumulated depreciation	368
Construction work in progress	$ 0
Ownership percentage (in hundredths)	50.00%

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Income Taxes (Details)		3 Months Ended	12 Months Ended
		Sep. 30, 2015	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2012	Dec. 31, 2016 USD ($) $ / kWh	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Consolidated Appropriations Act of 2016 [Abstract]
Excise Tax Delay			2 years
Unrecognized Tax Benefits, Interest on Income Taxes Accrued							$ (1,100,000)	$ (400,000)	$ (200,000)	$ (100,000)
Interest Income (Expense) related to unrecognized tax benefits			$ (700,000)	$ (200,000)	$ (100,000)
Unrecognized Tax Benefits, Income Tax Penalties Accrued							0	0	0
Tax Increase Prevention Act of 2014 [Abstract]
Number of years bonus depreciation was extended					1 year
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions							2,900,000	2,400,000
Unrecognized tax benefit — Temporary tax positions							16,800,000	15,000,000
Total unrecognized tax benefit			17,400,000	11,900,000	$ 8,400,000		19,700,000	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			17,400,000	11,900,000	8,400,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions			2,700,000	4,500,000	3,700,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions			0	(1,500,000)	(700,000)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions			500,000	2,500,000	2,800,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions			(900,000)	0	(1,200,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities			0	0	(1,100,000)
Balance at Dec. 31			$ 19,700,000	$ 17,400,000	$ 11,900,000
Tax Benefits Associated With Nol And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards							(5,800,000)	(4,300,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible							11,000,000
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%	3.20%	2.80%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent			(0.70%)	(0.70%)	(0.80%)
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent			(0.50%)	(0.30%)	(2.10%)
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent			0.00%	0.10%	(0.10%)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent			0.10%	0.10%	0.10%
Effective Income Tax Rate Reconciliation, Percent			37.10%	37.40%	34.90%
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)			$ 45,287,000	$ (1,166,000)	$ 9,550,000
Current State and Local Tax Expense (Benefit)			8,754,000	(727,000)	2,611,000
Current Change In Unrecognized Tax Expense (Benefit)			680,000	5,244,000	6,548,000
Deferred Federal Income Tax Expense (Benefit)			195,064,000	246,096,000	208,781,000
Deferred State and Local Income Tax Expense (Benefit)			27,216,000	36,450,000	26,196,000
Deferred Change In Unrecognized Tax Expense (Benefit)			(278,000)	(4,650,000)	(7,154,000)
Deferred investment tax credits			(2,805,000)	(2,807,000)	(2,941,000)
Income Tax Expense (Benefit)			273,918,000	278,440,000	243,591,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items			230,931,000	285,144,000	254,142,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities			(8,418,000)	(7,229,000)	(26,649,000)
Other Comprehensive Income (Loss), Tax			(511,000)	(19,000)	330,000
Deferred Income Tax Expense (Benefit)			$ 222,002,000	$ 277,896,000	$ 227,823,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment							2,967,162,000	2,772,043,000
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits							87,693,000	105,049,000
Deferred Tax Liabilities, Other							69,931,000	82,732,000
Deferred Tax Liabilities, Gross							3,124,786,000	2,959,824,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards							115,328,000	147,763,000
Deferred Tax Assets Tax credit carryforward							34,658,000	35,240,000
Deferred Tax Assets Regulatory Liabilities							19,635,000	17,201,000
Deferred Tax Assets Deferred Investment Tax Credits							11,653,000	12,718,000
Deferred Tax Assets Unbilled Revenue Fuel Costs							10,070,000	29,694,000
Deferred Tax Assets Rate Refund							7,221,000	23,352,000
Deferred Tax Assets, Other							37,092,000	35,658,000
Deferred Tax Assets, Net of Valuation Allowance							235,657,000	301,626,000
Deferred Tax Liabilities, Net							2,889,129,000	2,658,198,000
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Earliest year subject to examination			2009
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							260,000,000	328,000,000
Tax Credit Carryforward, Amount							25,000,000	24,000,000
Carryforward expiration date range, low			2021
Carryforward expiration date range, high			2036
State and Local Jurisdiction
Tax Audits [Abstract]
Earliest year subject to examination			2009
Operating Loss Carryforwards							684,000,000	684,000,000
Tax Credit Carryforward Net Of Federal Detriment	[1]						13,000,000	13,000,000
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit	[2]						(3,000,000)	(1,000,000)
Federal detriment							7,000,000	7,000,000
Federal Benefit							$ 2,000,000	$ 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%

[1] (a) State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2016 and 2015, respectively.

[2] (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $1 million as of Dec. 31, 2016 and 2015, respectively.

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Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2016 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	1,984

XML

Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2016
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

XML

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 3,800	$ 3,600
Net benefit cost recognized for financial reporting	600	600
Pension Plans
Pension Benefits [Abstract]
Total benefit obligation	1,251,822	1,224,650	$ 1,277,957
Net benefit cost recognized for financial reporting	$ 37,486	$ 38,304	$ 37,307
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)	6.84%	6.81%	6.81%
Expected average long-term rate of return on assets for next fiscal year (as a percent)	6.62%
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%	36.00%
Pension Plans | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	31.00%	32.00%
Pension Plans | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	15.00%	12.00%
Pension Plans | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	16.00%	18.00%
Pension Plans | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	2.00%	2.00%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 43,500	$ 41,800
Net benefit cost recognized for financial reporting	$ 7,900	$ 9,500

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Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plans - USD ($) $ in Thousands		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 1,004,213		$ 1,036,681		$ 1,103,865
Plan asset investments measured at net asset value		678,369	[1]	626,043	[2]
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		62,305		110,751
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		263,539		299,887
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		34,957		81,954
Plan asset investments measured at net asset value		0	[1]	0	[2]
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		34,957		81,954
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
Plan asset investments measured at net asset value	[2]			0
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				1,204
Derivatives | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		165,621		125,011
Plan asset investments measured at net asset value		165,621	[1]	125,011	[2]
U.S. equity 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
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equity 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
Non U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		122,197		119,394
Plan asset investments measured at net asset value		122,197	[1]	119,394	[2]
Non U.S. equity 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
Non U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. equity 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
U.S. corporate bond funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		96,995		82,827
Plan asset investments measured at net asset value		96,995	[1]	82,827	[2]
U.S. corporate bond 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
U.S. corporate bond funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. corporate bond 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
Emerging market equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		64,784		56,525
Plan asset investments measured at net asset value		64,784	[1]	56,525	[2]
Emerging market equity 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
Emerging market equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market equity 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
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		53,703		54,362
Plan asset investments measured at net asset value		53,703	[1]	54,362	[2]
Emerging market debt 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
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market debt 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
Commodity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		7,497		14,169
Plan asset investments measured at net asset value		7,497	[1]	14,169	[2]
Commodity 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
Commodity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Commodity 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
Private equity investments
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		31,828		34,353
Plan asset investments measured at net asset value		31,828	[1]	34,353	[2]
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		0		0
Real estate
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		61,048		67,075
Plan asset investments measured at net asset value		61,048	[1]	67,075	[2]
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		0		0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		74,696		72,327
Plan asset investments measured at net asset value		74,696	[1]	72,327	[2]
Other 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
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other 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
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		168,014		214,341
Plan asset investments measured at net asset value		0	[1]	0	[2]
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		168,014		214,341
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
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		86,081		74,787
Plan asset investments measured at net asset value		0	[1]	0	[2]
U.S. 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
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		86,081		74,787
U.S. 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
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		13,828		12,127
Plan asset investments measured at net asset value		0	[1]	0	[2]
Non U.S. 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
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		13,828		12,127
Non U.S. 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
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		2,179
Plan asset investments measured at net asset value	[1]	0
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		2,179
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
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,032		881
Plan asset investments measured at net asset value		0	[1]	0	[2]
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,032		881
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
U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		27,348		28,797
Plan asset investments measured at net asset value		0	[1]	0	[2]
U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		27,348		28,797
U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equities | 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		(7,595)		(3,453)
Plan asset investments measured at net asset value		0	[1]	0	[2]
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		(7,595)		(3,453)
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] Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

[2] Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

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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, 2017 USD ($)	Dec. 31, 2016 USD ($) Plan	Dec. 31, 2015 USD ($) Plan	Dec. 31, 2014 USD ($) Plan
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			$ 1,213,890	$ 1,192,798
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 1,251,822	1,224,650	1,277,957
Service cost			25,926	28,260	$ 23,939
Interest cost			55,405	50,857	53,277
Transfer (to) from other plan			(9,149)	(2,938)
Plan amendments			206	0
Actuarial (gain) loss			51,779	(54,737)
Benefit payments			(96,995)	(74,749)
Obligation at Dec. 31			1,251,822	1,224,650	1,277,957
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		1,004,213	1,036,681	1,103,865
Actual return (loss) on plan assets			56,762	(9,122)
Employer contributions			16,829	20,056
Transfer (to) from other plan			(9,064)	(3,369)
Benefit payments			(96,995)	(74,749)
Fair value of plan assets at Dec. 31			1,004,213	1,036,681	1,103,865
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]		(247,609)	(187,969)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			554,999	521,703
Prior service (credit) cost			(12,155)	(15,572)
Total			542,844	506,131
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			515,708	28,852
Noncurrent regulatory assets			26,853	477,279
Deferred income taxes			108	0
Net-of-tax accumulated OCI			175	0
Total			$ 542,844	$ 506,131
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			4.13%	4.66%
Expected average long-term increase in compensation level (as a percent)			3.75%	4.00%
Mortality table			RP-2014	RP-2014
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 16,800	$ 20,100	35,200
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			25,926	28,260	23,939
Interest cost			55,405	50,857	53,277
Expected return on plan assets			(70,769)	(72,590)	(70,709)
Amortization of prior service (credit) cost			(3,211)	(3,136)	(3,092)
Amortization of net loss			26,771	36,377	33,892
Net periodic pension cost			34,122	39,768	37,307
Costs not recognized due to regulation			3,364	(1,464)	0
Net benefit cost recognized for financial reporting			$ 37,486	$ 38,304	$ 37,307
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.66%	4.11%	4.75%
Expected average long-term increase in compensation level (as a percent)			4.00%	3.75%	3.75%
Expected average long-term rate of return on assets (as a percent)			6.84%	6.81%	6.81%
Allocated costs for pension plans sponsored by Xcel Energy Inc.			$ 9,400	$ 9,900	$ 9,400
Expected average long-term rate of return on assets for next fiscal year (as a percent)			6.62%
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			$ 125,200	$ 90,100	$ 130,600
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]
Total contributions to Xcel Energy's pension plans during the period		$ 150,000

[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 9.9	$ 9.5	$ 9.1

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Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Postretirement Benefit Plan	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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, 2016		Dec. 31, 2015		Dec. 31, 2014
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 393,555		$ 399,442		$ 425,282
Plan assets at net asset value		148,605	[1]	182,736	[2]
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		54,750		17,524
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		190,200		199,182
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		18,288		17,524
Plan assets at net asset value		0	[1]	0	[2]
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		18,288		17,524
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
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		42,046		42,123
Plan assets at net asset value		0	[1]	0	[2]
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		42,046		42,123
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
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		48,462		34,089
Plan assets at net asset value		48,462	[1]	34,089	[2]
U.S. equity 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
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equity 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
Non U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				29,979
Plan assets at net asset value	[2]			29,979
Non U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Non U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Non U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
U.S fixed income funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		24,132		21,638
Plan assets at net asset value		24,132	[1]	21,638	[2]
U.S fixed income 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
U.S fixed income funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S fixed income 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
Emerging market equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				9,901
Plan assets at net asset value	[2]			9,901
Emerging market equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Emerging market equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Emerging market equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		27,089		31,827
Plan assets at net asset value		27,089	[1]	31,827	[2]
Emerging market debt 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
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market debt 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 commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		48,922		55,302
Plan assets at net asset value		48,922	[1]	55,302	[2]
Other 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
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other 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
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		33,600		35,016
Plan assets at net asset value		0	[1]	0	[2]
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		33,600		35,016
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
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		55,473		53,433
Plan assets at net asset value		0	[1]	0	[2]
U.S. 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
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		55,473		53,433
U.S. 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
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		15,384		11,598
Plan assets at net asset value		0	[1]	0	[2]
Non U.S. 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
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		15,384		11,598
Non U.S. 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		16,845		25,602
Plan assets at net asset value		0	[1]	0	[2]
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		16,845		25,602
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
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		25,563		31,778
Plan assets at net asset value		0	[1]	0	[2]
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		25,563		31,778
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
Non U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		36,462
Plan assets at net asset value	[1]	0
Non U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		36,462
Non U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Non U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,289		(368)
Plan assets at net asset value		0	[1]	0	[2]
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,289		(368)
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] Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

[2] Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

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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, 2016	Dec. 31, 2015	Dec. 31, 2014
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 403,574	$ 443,753
Service cost		768	928	$ 1,915
Interest cost		18,070	17,498	23,704
Medicare subsidy reimbursements		1,901	1,712
Plan participants' contributions		5,376	4,961
Actuarial (gain) loss		27,355	(32,001)
Benefit payments		(35,221)	(33,277)
Obligation at Dec. 31		421,823	403,574	443,753
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		399,442	425,282
Actual return (loss) on plan assets		18,590	(3,076)
Plan participants' contributions		5,376	4,961
Employer contributions		5,368	5,552
Benefit payments		(35,221)	(33,277)
Fair value of plan assets at Dec. 31		393,555	399,442	425,282
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]	(28,268)	(4,132)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		78,359	49,226
Prior service (credit) cost		(27,695)	(33,942)
Total		50,664	15,284
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		$ 50,664	$ 15,284
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		4.13%	4.65%
Mortality table		RP 2014	RP 2014
Health care costs trend rate - initial (as a percent)		5.50%	6.00%
Ultimate health care trend assumption rate (as a percent)		4.50%	4.50%
Period until ultimate trend rate is reached (in years)		2 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO		$ 40,100
One-percent decrease in APBO		(34,155)
One-percent increase in service and interest components		1,980
One-percent decrease in service and interest components		(1,677)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		5,400	$ 5,600	5,500
Expected contribution to postretirement health care plans during 2017		0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		768	928	1,915
Interest cost		18,070	17,498	23,704
Expected return on plan assets		(22,299)	(23,803)	(30,214)
Amortization of prior service (credit) cost		(6,247)	(6,247)	(6,247)
Amortization of net loss		1,931	2,475	6,434
Net periodic pension cost		$ (7,777)	$ (9,149)	$ (4,408)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		4.65%	4.08%	4.82%
Expected average long-term rate of return on assets (as a percent)		5.80%	5.80%	7.18%
Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		$ 17,900	$ 18,300	$ 17,100
Expected contribution to postretirement health care plans during 2017		$ 11,800

[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, 2016 USD ($)
Pension Plans
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2017	$ 79,506
2018	78,738
2019	80,914
2020	81,095
2021	82,084
2022-2026	417,876
Postretirement Benefit Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2017	33,912
2018	33,652
2019	33,467
2020	33,991
2021	33,588
2022-2026	156,773
Expected Medicare Part D Subsidies [Abstract]
2017	2,140
2018	2,266
2019	2,383
2020	2,475
2021	2,574
2022-2026	14,246
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2017	31,772
2018	31,386
2019	31,084
2020	31,516
2021	31,014
2022-2026	$ 142,527

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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, 2016 USD ($) gal MWh MMBTU Counterparty	Dec. 31, 2015 gal MWh MMBTU
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		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		7
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		4
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 21.1
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		35.00%
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		6
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 8.8
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		15.00%
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 (in megawatt hours)
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1],[2]	6,283	684
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	42,203	12,515
Vehicle Fuel Commodity (in gallons)
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Derivative, Nonmonetary Notional amount | gal	[1],[2]	0	63

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

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

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Other Income, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Income and Expenses [Abstract]
Interest income	$ 1,860	$ 753	$ 1,470
Other nonoperating income	2,241	2,408	3,601
Insurance Policy Expense (Income), Net	(281)	(197)	(806)
Other Nonoperating Expense	(3)	0	0
Other income, net	$ 3,817	$ 2,964	$ 4,265

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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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ (23,836)	$ (23,878)	$ (23,338)
After-tax net unrealized (losses) related to derivatives accounted for as hedges	0	(30)	(72)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	1,056	72	(468)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ (22,780)	$ (23,836)	$ (23,878)

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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		0	(50,000)	(115,000)
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		1,704,000	111,000	(755,000)
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]	1,618,000	54,000	(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		0	(50,000)	(115,000)
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]	86,000	57,000	(25,000)
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		2,051,000	(10,635,000)	451,000
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)		10,292,000	10,158,000	(4,631,000)
Pre-tax gains (losses) recognized during the period in income		(6,089,000)	(7,256,000)	(9,850,000)
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	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0
Pre-tax gains (losses) recognized during the period in income	[3]	(257,000)	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		2,051,000	(10,635,000)	451,000
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]	10,292,000	10,158,000	(4,631,000)
Pre-tax gains (losses) recognized during the period in income	[4]	(5,832,000)	(7,620,000)	$ (9,850,000)
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 fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		$ (200,000)	$ (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, 2016 and Dec. 31, 2015 included $0.2 million and $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 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2016, 2015 and 2014 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.

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Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 0	$ 0
Collateral posted on derivative instruments	0	0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		10,934		1,945
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3,398		3,478
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		6,788		8,881
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		7,828		13,020
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		9,218		230
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(5,137)	[1]	(610)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,440		164
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(5,137)	[1]	(324)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		7,778		66
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		0	[1]	(286)	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,652		16
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				16
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[2]			0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,652
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,628		3,691
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(5,137)	[1]	(610)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				92
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[2]			0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,628		35
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(5,137)	[1]	(324)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				3,564
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[2]			(286)
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				33
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[2]			0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				33
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[2]			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,124		137
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,124		137
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,386		34
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,386		34
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		13,231		703
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5,453		351
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		7,778		352
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,652		16
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				16
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,652
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		5,357		4,267
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				92
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		5,357		325
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				3,850
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				33
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				33
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		22		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		22		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				0
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,716	[3]	1,715	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,746	[3]	3,462	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		5,160	[3]	5,190	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		7,828	[3]	12,987	[4]
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14,355		840
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		6,577		488
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		7,778		352
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,652		16
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				16
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,652
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		6,765		4,301
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				92
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		$ 6,765		359
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				3,850
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				33
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability				$ 33

[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, 2016. At Dec. 31, 2016, 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, 2015. At Dec. 31, 2015, 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.

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Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Transfers into Level 3	$ 0	$ 0	$ 0
Transfers out of Level 3	$ 0	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,216,206	$ 4,105,596
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,491,570	$ 4,376,875

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Rate Matters (Details) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2017 USD ($)	Dec. 31, 2016 USD ($) GWh	Dec. 31, 2015 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011
CPUC Proceeding - Annual Electric Earnings Test 2015 through 2017
Rate Matters [Abstract]
Public Utilities, Return on Equity Threshold for Earnings Sharing		9.83%
CPUC Proceeding - Demand Side Management Cost Adjustment
Rate Matters [Abstract]
Public Utilities, Incentive Award Upon Achieving Savings Goal		$ 5.0
Public Utilities, Percentage of Net Economic Benefits on Which Incentive is Earned		5.00%
Public Utilities, Maximum Annual Incentive		$ 30.0
Demand Side Management Cost Adjustment, 2015
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (in GWh) | GWh		400
Demand Side Management Cost Adjustment, 2016
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (in GWh) | GWh		400
Demand Side Management Cost Adjustment, 2017 through 2020
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (in GWh) | GWh		400
Public Utilities, Annual Spending Limit		$ 84.3
CPUC Proceeding - Renewable Energy Credit Sharing
Rate Matters [Abstract]
Public Utilities, Customers Share of Margins Credited Against RESA Regulatory Asset Balance		5.8	$ 5.5
Public Utilities, Cumulative Credit Against RESA Regulatory Asset Balance		$ 116.3	$ 110.6
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Renewable Energy Credit Sharing
Rate Matters [Abstract]
Public Utilities, Margin Threshold Determining Percentage of Margin Sharing				$ 20.0
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%
Subsequent Event | Colorado Public Utilities Commission (CPUC) | Demand Side Management Cost Adjustment, 2017 Budget
Rate Matters [Abstract]
Public Utilities, Approved Electric Demand Side Management Budget	$ 80.4
Public Utilities, Approved Gas Demand Side Management Budget	13.1
Subsequent Event | Colorado Public Utilities Commission (CPUC) | Demand Side Management Cost Adjustment, 2018 Budget
Rate Matters [Abstract]
Public Utilities, Approved Electric Demand Side Management Budget	77.7
Public Utilities, Approved Gas Demand Side Management Budget	$ 12.8

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Commitments and Contingencies, Capital Commitments (Details)	12 Months Ended
	Dec. 31, 2016 MW
Capital Commitments | Rush Creek Wind Farm [Member]
Capital Commitments [Abstract]
Public Utilities, Facility Generating Capacity	600

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Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Coal
Fuel Contracts [Abstract]
2017	$ 241.2
2018	143.1
2019	68.6
2020	48.5
2021	49.6
Thereafter	293.4
Total	844.4
Natural Gas Supply
Fuel Contracts [Abstract]
2017	293.6
2018	185.7
2019	179.7
2020	184.3
2021	191.5
Thereafter	171.2
Total	1,206.0
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2017	117.8
2018	69.0
2019	37.1
2020	36.6
2021	34.4
Thereafter	609.9
Total	$ 904.8
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2017
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2060

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Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Long-term Contract for Purchase of Electric Power [Line Items]
Purchase Power Agreement Expiration Date		2032
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity		$ 44.0	$ 69.5	$ 69.5
Estimated Future Payments Under PPAs [Abstract]
2017		24.3
2018		20.1
2019		11.5
2020		3.0
2021		3.0
Thereafter		16.4
Total		78.3
Energy
Estimated Future Payments Under PPAs [Abstract]
2017	[1]	4.4
2018	[1]	0.0
2019	[1]	0.0
2020	[1]	0.0
2021	[1]	0.0
Thereafter	[1]	0.0
Total	[1]	$ 4.4

[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, 2016 USD ($) Lease	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Capital Leases [Abstract]
Number of leases qualifying as capital leases | Lease		3
Amortization expense under capital lease assets		$ 8.1	$ 8.2	$ 7.2
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease		221.2	221.2
Accumulated depreciation		(65.3)	(57.2)
Total property held under capital leases, net		155.9	164.0
Capital Leases, Future Minimum Payments Due [Abstract]
2017		25.7
2018		25.3
2019		25.1
2020		24.9
2021		23.8
Thereafter		462.7
Total minimum obligation		587.5
Interest component of obligation		(431.6)
Present value of minimum obligation		$ 155.9
Operating Leased Assets [Line Items]
Operating Lease Purchase Power Agreement Expiration Date		2032
Operating Leases, Future Minimum Payments Due [Abstract]
2017		$ 107.3
2018		106.8
2019		107.8
2020		108.7
2021		109.1
Thereafter		$ 528.9
WYCO Totem Gas Storage Facilities
Capital Leases [Abstract]
Ownership interest in joint venture (in hundredths)		50.00%
Capital lease obligations		$ 127.0	132.9
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		118.2	130.5	126.2
Operating Leases, Future Minimum Payments Due [Abstract]
2017		11.0
2018		10.2
2019		10.3
2020		10.3
2021		9.7
Thereafter		45.2
Purchased Power Agreements
Operating Leases [Abstract]
Payments for capacity for PPAs under operating lease obligations		102.4	$ 113.5	$ 110.1
Operating Leases, Future Minimum Payments Due [Abstract]
2017	[1],[2]	96.3
2018	[1],[2]	96.6
2019	[1],[2]	97.5
2020	[1],[2]	98.4
2021	[1],[2]	99.4
Thereafter	[1],[2]	$ 483.7

[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, 2016	Dec. 31, 2015
Purchased Power Agreements (PPAs) [Abstract]
VIE Purchase Power Agreement Expiration Date	2032
Independent Power Producing Entities
Purchased Power Agreements (PPAs) [Abstract]
Generating capacity (in MW)	1,571	1,802

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Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) Site	Dec. 31, 2015 USD ($) Period
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
National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of Hours Measured for Standard | Period		8
Former Level of Air Quality Concentrations (in parts per billion)		75
Revised 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	$ 1.7

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Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 240,508	[1]	$ 225,296
Liabilities recognized	214		0
Liabilities settled	0		0
Accretion	10,257		9,575
Cash Flow Revisions	38,584	[2]	5,637	[3]
Ending balance	289,563	[4]	240,508	[1]
Electric Plant Steam and Other Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	38,676	[1]	36,856
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	1,877		1,820
Cash Flow Revisions	(103)	[2]	0	[3]
Ending balance	40,450	[4]	38,676	[1]
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	70,767	[1]	61,885
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	3,078		2,769
Cash Flow Revisions	(1,245)	[2]	6,113	[3]
Ending balance	72,600	[4]	70,767	[1]
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,992	[1]	2,095
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	19		18
Cash Flow Revisions	61	[2]	(121)	[3]
Ending balance	2,072	[4]	1,992	[1]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,130	[1]	1,182
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	45		47
Cash Flow Revisions	6,494	[2]	(99)	[3]
Ending balance	7,669	[4]	1,130	[1]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,054	[1]	1,150
Liabilities recognized	214		0
Liabilities settled	0		0
Accretion	46		46
Cash Flow Revisions	206	[2]	(142)	[3]
Ending balance	1,520	[4]	1,054	[1]
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	122,168	[1]	117,474
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	5,009		4,694
Cash Flow Revisions	33,542	[2]	0	[3]
Ending balance	160,719	[4]	122,168	[1]
Natural Gas Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	3,925	[1]	3,886
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	155		153
Cash Flow Revisions	0	[2]	(114)	[3]
Ending balance	4,080	[4]	3,925	[1]
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	796	[1]	768
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	28		28
Cash Flow Revisions	(371)	[2]	0	[3]
Ending balance	$ 453	[4]	$ 796	[1]

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

[2] (a) In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains.

[3] (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.

[4] (b) There were no ARO liabilities settled during the year ended Dec. 31, 2016.

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Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 367	$ 364

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Commitments and Contingencies, Legal Contingencies (Details)	1 Months Ended		12 Months Ended
	Oct. 31, 2016 USD ($)	Dec. 31, 2015	Dec. 31, 2016 USD ($)
Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Accrual For Legal Contingency			$ 0
PSCo | Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Litigation Settlement, Amount	$ 15,000
PSCo | Line Extension Disputes
Legal Contingencies [Abstract]
Accrual For Legal Contingency			$ 0
Loss Contingency, Number of Plaintiffs			2
Maximum | PSCo | Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Amount of Sales Claimed as Subject to Refund			$ 50,000,000
Minimum | PSCo | Pacific Northwest FERC Refund Proceeding
Legal Contingencies [Abstract]
Amount of Sales Claimed as Subject to Refund			$ 34,000,000
Minimum | PSCo | Line Extension Disputes
Legal Contingencies [Abstract]
Loss Contingency, Number of Plaintiffs		50

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Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 103,783	$ 92,072
Regulatory Asset, Noncurrent		958,429	906,275
Past expenditures not currently earning a return		$ 28,000	54,000
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current	[1]	$ 27,270	29,260
Regulatory Asset, Noncurrent	[1]	568,258	497,973
Non Qualified Pension Plan
Regulatory Assets [Line Items]
Regulatory Asset, Current		400	400
Regulatory Asset		$ 4,200	4,400
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		$ 151,022	144,953
Depreciation Differences
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Pending rate case
Regulatory Asset, Current		$ 15,363	14,221
Regulatory Asset, Noncurrent		$ 90,426	99,835
Net AROs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current	[2]	$ 0	0
Regulatory Asset, Noncurrent	[2]	$ 78,050	62,948
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related contract
Regulatory Asset, Current		$ 1,035	1,319
Regulatory Asset, Noncurrent		$ 29,029	29,143
Conservation Programs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		One to two years
Regulatory Asset, Current	[3]	$ 9,262	8,466
Regulatory Asset, Noncurrent	[3]	$ 6,986	6,947
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related debt
Regulatory Asset, Current		$ 1,203	1,421
Regulatory Asset, Noncurrent		$ 6,120	6,957
Contract Valuation Adjustments
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related contract
Regulatory Asset, Current	[4]	$ 3,444	9,376
Regulatory Asset, Noncurrent	[4]	$ 6,082	9,526
Gas Pipeline Inspection Costs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Two years
Regulatory Asset, Current		$ 0	3,611
Regulatory Asset, Noncurrent		$ 4,405	0
Property Tax
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 9,393	21,558
Regulatory Asset, Noncurrent		$ 1,653	14,428
CACJA Recovery Rider
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Less than one year
Regulatory Asset, Current		$ 24,260	0
Regulatory Asset, Noncurrent		$ 0	20,020
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 12,553	2,840
Regulatory Asset, Noncurrent		$ 16,398	$ 13,545

[1] (a) Includes $4.2 million and $4.4 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2016 and 2015, respectively.

[2] (b) Includes amounts recorded for future recovery of AROs.

[3] (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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

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Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 101,110	$ 152,823
Regulatory Liability, Noncurrent		$ 512,933	471,421
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Plant lives
Regulatory Liability, Current		$ 0	0
Regulatory Liability, Noncurrent		$ 367,440	364,291
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Various
Regulatory Liability, Current		$ 3,600	3,311
Regulatory Liability, Noncurrent		$ 67,728	40,988
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Various
Regulatory Liability, Current		$ 0	0
Regulatory Liability, Noncurrent		$ 18,797	20,515
Deferred Income Tax Adjustment
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Various
Regulatory Liability, Current		$ 0	0
Regulatory Liability, Noncurrent		$ 16,260	16,891
Gain From Asset Sales
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Pending rate case
Regulatory Liability, Current		$ 0	0
Regulatory Liability, Noncurrent		$ 1,469	0
PSCo Earnings Test
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		One to two years
Regulatory Liability, Current		$ 8,300	42,868
Regulatory Liability, Noncurrent		$ 914	9,472
Deferred Electric, Gas, and Steam Production Costs
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Less than one year
Regulatory Liability, Current		$ 35,123	66,696
Regulatory Liability, Noncurrent		$ 0	0
Conservation Programs
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Less than one year
Regulatory Liability, Current	[2]	$ 24,077	33,460
Regulatory Liability, Noncurrent	[2]	$ 0	0
Gas Pipeline Inspection Costs
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Less than one year
Regulatory Liability, Current		$ 5,108	1,140
Regulatory Liability, Noncurrent		$ 0	4,273
Low Income Discount Program
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Less than one year
Regulatory Liability, Current		$ 881	1,393
Regulatory Liability, Noncurrent		$ 0	0
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Noncurrent Liability, Amortization Period		Various
Regulatory Liability, Current		$ 24,021	3,955
Regulatory Liability, Noncurrent		40,325	14,991
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		$ 2,400	$ 9,100

[1] (b) Revenue subject to refund of $2.4 million and $9.1 million for 2016 and 2015, respectively, is included in other current liabilities.

[2] (a) 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, 2016	Dec. 31, 2015
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ 5,120,152
(Gains) losses reclassified from net accumulated other comprehensive loss	1,059	$ 72
Accumulated other comprehensive loss at end of period	5,269,455	5,120,152
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(23,836)	(23,878)
Other comprehensive income (loss) before reclassifications	0	(30)
(Gains) losses reclassified from net accumulated other comprehensive loss	1,056	72
Net current period other comprehensive income (loss)	1,056	42
Accumulated other comprehensive loss at end of period	(22,780)	(23,836)
Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	0
Other comprehensive income (loss) before reclassifications	(223)
(Gains) losses reclassified from net accumulated other comprehensive loss	3
Net current period other comprehensive income (loss)	(220)
Accumulated other comprehensive loss at end of period	(220)	0
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(23,836)
Other comprehensive income (loss) before reclassifications	(223)
(Gains) losses reclassified from net accumulated other comprehensive loss	1,059
Net current period other comprehensive income (loss)	836
Accumulated other comprehensive loss at end of period	$ (23,000)	$ (23,836)

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Other Comprehensive Income - Reclassification from AOCI (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses		$ 762,416		$ 761,901	$ 751,786
Total, pre-tax		(737,409)		(745,242)	(698,779)
Income tax expense (benefit)		273,918		278,440	$ 243,591
Total amounts reclassified, net of tax		(1,059)		(72)
Gains and Losses on Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax		(1,056)		(72)
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		1,704		111
Income tax expense (benefit)		(648)		(39)
Total, net of tax		1,056		72
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]	1,618		54
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]	86		57
Amortization of net losses | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		5	[3]	0
Defined Benefit Pension and Postretirement Items
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax		(3)
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		(5)		0
Tax Benefit		2		0
Total amounts reclassified, net of tax		$ 3		$ 0

[1] (a) Included in interest charges.

[2] (b) Included in O&M expenses

[3] (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans.

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Segments and Related Information (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Intercompany Revenue										$ 13,000	$ 13,000	$ 14,000
Operating revenues		$ 1,020,926	$ 1,059,177	$ 909,852	$ 1,057,841	$ 1,030,838	$ 1,044,704	$ 952,521	$ 1,135,450	4,047,796	4,163,513	4,383,149
Depreciation and amortization										443,555	411,667	379,202
Total interest charges and financing costs										174,586	171,908	154,640
Income tax expense (benefit)										273,918	278,440	243,591
Net income (loss)		$ 86,666	$ 173,607	$ 87,344	$ 115,874	$ 84,255	$ 173,081	$ 98,500	$ 110,966	463,491	466,802	455,188
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues										3,049,627	3,115,558	3,126,276
Depreciation and amortization										337,583	311,122	285,968
Total interest charges and financing costs										136,274	136,397	124,118
Income tax expense (benefit)										228,825	234,873	208,095
Net income (loss)										383,973	391,257	349,793
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues										957,831	1,006,733	1,215,504
Depreciation and amortization										101,663	96,384	89,186
Total interest charges and financing costs										37,881	34,935	29,987
Income tax expense (benefit)										45,960	44,192	50,874
Net income (loss)										75,426	74,267	84,324
All Other
Segment Reporting Information [Line Items]
Operating revenues										40,723	41,590	41,888
Depreciation and amortization										4,309	4,161	4,048
Total interest charges and financing costs										431	576	535
Income tax expense (benefit)										(867)	(625)	(15,378)
Net income (loss)										4,092	1,278	21,071
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	[1]									4,047,796	4,163,513	4,383,149
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	[1]									3,049,352	3,115,257	3,125,937
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	[1]									957,721	1,006,666	1,215,324
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	[1]									40,723	41,590	41,888
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues										(385)	(368)	(519)
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										275	301	339
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues										110	67	180
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues										$ 0	$ 0	$ 0

[1] Operating revenues include $13 million, $13 million and $14 million of intercompany revenue for the years ended Dec. 31, 2016, 2015 and 2014, 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues
Electric	$ 8,809	$ 8,632	$ 9,614
Other	4,525	4,441	4,441
Operating expenses
Purchased power	56	0	23
Other operating expenses - paid to Xcel Energy Services Inc.	446,086	414,620	454,250
Interest expense	149	211	158
Interest income	0	45	$ 61
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	9,421	4,909
Accounts payable	98,797	76,643
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	7,669	4,419
Accounts payable	0	0
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	974	71
Accounts payable	0	0
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	745	414
Accounts payable	0	0
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	33	5
Accounts payable	$ 98,797	$ 76,643

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Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 1,020,926	$ 1,059,177	$ 909,852	$ 1,057,841	$ 1,030,838	$ 1,044,704	$ 952,521	$ 1,135,450	$ 4,047,796	$ 4,163,513	$ 4,383,149
Operating income	170,197	315,605	180,629	223,190	173,951	315,174	195,176	215,400	889,621	899,701	802,370
Net income	$ 86,666	$ 173,607	$ 87,344	$ 115,874	$ 84,255	$ 173,081	$ 98,500	$ 110,966	$ 463,491	$ 466,802	$ 455,188

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Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 20,122	$ 23,122	$ 22,505
Charged to costs and expenses		14,121	13,052	17,005
Charged to other accounts	[1]	4,447	5,175	6,240
Deductions from reserves	[2]	19,078	21,227	22,628
Balance at Dec. 31		$ 19,612	$ 20,122	$ 23,122

[1] Recovery of amounts previously written off.

[2] Deductions relate primarily to bad debt write-offs.