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, 2013

or

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

Commission File Number: 001-3280

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

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

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

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

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

As of Feb. 24, 2014, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Xcel Energy Inc.’s Definitive Proxy Statement for its 2014 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

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

TABLE OF CONTENTS

Index

PART I
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	8
Fuel Sources	8
Renewable Energy Sources	9
Wholesale Commodity Marketing Operations	9
Summary of Recent Regulatory Developments	9
Electric Operating Statistics	10
NATURAL GAS UTILITY OPERATIONS	11
Overview	11
Public Utility Regulation	12
Capability and Demand	12
Natural Gas Supply and Costs	13
Natural Gas Operating Statistics	14
GENERAL	14
ENVIRONMENTAL MATTERS	15
EMPLOYEES	15
Item 1A — Risk Factors	15
Item 1B — Unresolved Staff Comments	24
Item 2 — Properties	25
Item 3 — Legal Proceedings	25
Item 4 — Mine Safety Disclosures	25
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6 — Selected Financial Data	26
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	29
Item 8 — Financial Statements and Supplementary Data	31
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	84
Item 9A — Controls and Procedures	84
Item 9B — Other Information	85
PART III
Item 10 — Directors, Executive Officers and Corporate Governance	85
Item 11 — Executive Compensation	85
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	85
Item 13 — Certain Relationships and Related Transactions, and Director Independence	85
Item 14 — Principal Accountant Fees and Services	85
PART IV
Item 15 — Exhibits, Financial Statement Schedules	86
SIGNATURES	91

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.

PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

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

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

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COMPANY OVERVIEW

PSCo was incorporated in 1924 under the laws of Colorado.  PSCo is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado.  The wholesale customers served by PSCo comprised approximately 13 percent of its total KWh sold in 2013.  PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.  PSCo provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 1.3 million customers.  All of PSCo’s retail electric operating revenues were derived from operations in Colorado during 2013.  Although PSCo’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large commercial and industrial electric sales include the following industries:  fabricated metal products, oil and gas extraction and communications.  For small commercial and industrial customers, significant electric retail sales include the following industries:  real estate and dining establishments.  Generally, PSCo’s earnings contribute approximately 45 percent to 55 percent of Xcel Energy’s consolidated net income.

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

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

PSCo corporate strategy focuses on four core objectives: driving operational excellence; providing options and solutions to customers; investing for the future; and enhancing engagement with employees, customers, shareholders, communities and policy makers.  PSCo files periodic rate cases and establishes formula rates or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations.  Environmental leadership is a core priority for PSCo and is designed to meet customer and policy maker expectations for clean energy at a competitive price while creating shareholder value.

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

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

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

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

• PCCA — The PCCA recovers purchased capacity payments.

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

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

• RESA — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of two percent of the customer’s total bill.

• Wind Energy Service — Wind Energy Service is a premium service for those customers who voluntarily choose to pay an additional charge to increase the level of renewable resource generation used to meet the customer’s load requirements.

• TCA — The TCA recovers transmission plant revenue requirements and allows for a return on CWIP outside of rate cases.

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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 regularly monitors and records, as necessary, an estimated customer refund obligation under the QSP. PSCo files its proposed rate adjustment annually under the QSP. The CPUC conducts proceedings to review and approve these rate adjustments annually. In 2013, the CPUC extended the terms of the current QSP through the end of 2015.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2014, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2011	2012	2013	2014 Forecast
PSCo	6,896	6,689	6,678	6,459

The peak demand for PSCo’s system typically occurs in the summer.  The 2013 uninterrupted system peak demand for PSCo occurred on June 27, 2013. Comanche Unit 3 was off line, which increased PSCo’s system load by approximately 260 MW for the backup power provided by PSCo to the joint owners.  The forecasted 2014 system peak is lower than the 2013 peak, primarily due to the assumption that Comanche Unit 3 will be on line at the time of the peak and excludes the demand for the backup power supplied in 2013.

Energy Sources and Related Transmission Initiatives

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

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

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

2011 ERP and 2013 All-Source Solicitation— In March 2013, PSCo issued an All-Source RFP for 250 MW of generation by the end of 2018. PSCo also issued a separate wind RFP for PPAs only.

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

• The addition of 450 MW of wind generation PPAs. This additional wind would bring the installed capacity on PSCo’s system in Colorado to 2,650 MW;

• The addition of 170 MW of utility-scale solar generation PPAs. PSCo currently has about 80 MW of utility-scale solar and approximately 188 MW of customer-sited solar generation;

• The addition of 317 MW of natural gas fired generation PPAs, which would come from existing power plants that previously supplied PSCo, but at reduced prices;

• Accelerated retirement of the 109 MW, coal-fired Unit 4 at the Arapahoe generating station, which occurred at the end of 2013;

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• Confirmation of the retirement of the 45 MW, coal-fired Unit 3 at the Arapahoe generating station, which occurred at the end of 2013; and

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

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

Boulder, Colo. Municipalization Exploration— PSCo’s franchise agreement with the City of Boulder expired on Dec. 31, 2010. In November 2010, the citizens of Boulder voted to impose an occupational tax to replace franchise fee revenues that would terminate when the franchise agreement terminated. In November 2011, two ballot measures were passed by the citizens of Boulder.  The first measure increased the occupation tax to raise an additional $1.9 million annually for funding the exploration costs of forming a municipal utility and acquiring the PSCo electric distribution system in Boulder.  The second measure authorized the formation and operation of a municipal light and power utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage.

Boulder Staff have performed a feasibility study on municipalization and in July 2013, recommended that Boulder create its own electric utility. In August 2013, the Boulder City Council voted to authorize the acquisition of PSCo’s transmission and distribution system in and near Boulder. On Jan. 6, 2014, Boulder sent PSCo a Notice of Intent to Acquire (NOIA) for PSCo’s transmission, distribution and property assets within an area that includes Boulder and certain areas outside city limits. The NOIA is a legal prerequisite to the filing of an eminent domain proceeding in Colorado courts. However, sending the NOIA does not require Boulder to move forward with a condemnation case.

Boulder’s municipalization plan assumes that Boulder will acquire through condemnation PSCo facilities (and customers currently served from these PSCo facilities) that are located outside Boulder’s incorporated limits. PSCo petitioned the CPUC for a declaratory ruling that Boulder cannot serve PSCo’s customers outside Boulder’s city limits without obtaining a CPCN from the CPUC. The CPUC declared that it has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine what facilities need to be constructed to ensure reliable service. The CPUC stated it believes that the cost of all new facilities must be paid by Boulder. The CPUC declared that it should make its determinations prior to any eminent domain actions. On Jan. 15, 2014, Boulder appealed this ruling to Boulder District Court.

If Boulder commences an eminent domain proceeding, PSCo will seek to obtain full compensation for the business and its associated property taken by Boulder, as well as for all damages resulting to PSCo and its system. PSCo would also seek appropriate compensation for stranded costs with the FERC.

RES Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales are supplied by renewable energy by 2020 and includes a distributed generation standard.  The CPUC has approved PSCo’s 2012 and 2013 RES compliance plan to acquire up to 30 MW of customer-sited solar projects each year and up to 9 MW of community solar garden projects, which PSCo met in both 2012 and 2013. The CPUC also approved moving solely to a pay-for-performance basis under the Solar*Rewards distributed solar generation program, which PSCo implemented in 2012.  Based on CPUC approval, PSCo implemented a solar gardens program called Solar*Rewards Community, which will allow customers to join together to own interests in a common solar facility and receive a credit related to their share of the solar garden’s electric production on their electric bill.  See Renewable Energy Sources for further discussion.

In July 2013, PSCo filed its 2014 RES compliance plan which included continuing both the Solar*Rewards and Solar*Rewards Community programs, maintaining approximately the same capacity expected to be installed in 2013. PSCo also proposed to show in aggregate the system costs that are not avoided by distributed solar generation, which PSCo has defined as a “net metering incentive.” In December 2013, parties including the OCC filed answer testimony supporting PSCo’s net metering proposal. However, rooftop solar advocates opposed it and also argued for higher solar installation levels and a slower reduction in incentives over time. Hearings are anticipated later in 2014 with a decision anticipated in the third quarter of 2014.

Steam System Package Boilers and Regulatory Plan— In December 2012, PSCo filed for a CPCN to construct two packaged boilers for its steam utility. The application also sought approval for PSCo’s regulatory plan affecting rates for natural gas and steam services effective after the boilers have been placed in service.  The proposed regulatory plan would combine the gas and steam revenue requirements for purposes of setting rates for retail gas and steam customers beginning January 2016.

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In December 2013, the CPUC denied the application. The regulatory plan was designed to minimize customer attrition and the CPUC suggested that PSCo survey all steam customers in order to ensure that the boilers are appropriately sized before refiling.

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
2013	$	1.84	80	%	$	4.86	20	%	$	2.45
2012	1.77		78		4.25		22		2.31
2011	1.77		76		4.98		24		2.54

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, 2013 and 2012 were approximately 41 and 46 days usage, respectively.  PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming.  During 2013 and 2012, PSCo’s coal requirements for existing plants were approximately 11.3 million tons.  The estimated coal requirements for 2014 are approximately 10.5 million tons.

PSCo has contracted for coal supply to provide 100 percent of its estimated coal requirements in 2014, and a declining percentage of requirements in subsequent years.  PSCo’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

PSCo has coal transportation contracts that provide for delivery of 100 percent of its coal requirements in 2014 and 2015.  Coal delivery may be subject to short-term 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 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.  These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers.  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, 2013, PSCo’s commitments related to gas supply contracts, which expire in various years from 2014 through 2023, were approximately $1.1 billion and commitments related to gas transportation and storage contracts, which expire in various years from 2014 through 2060, were approximately $723 million.  At Dec. 31, 2012, PSCo’s commitments related to gas supply contracts were approximately $1.1 billion and commitments related to gas transportation and storage contracts were approximately $754 million.

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

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Renewable Energy Sources

PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs.As of Dec. 31, 2013, PSCo was in compliance with mandated RPS, which require generation from renewable resources of 12 percent of electric retail sales.  Renewable energy comprised 21.9 percent and 18.4 percent of PSCo’s total owned and purchased energy for 2013 and 2012, respectively.  Wind energy comprised 19.3 percent and 16.0 percent of PSCo’s total owned and purchased energy for 2013 and 2012, respectively.  Hydroelectric, biomass and solar power comprised approximately 2.6 percent and 2.4 percent of PSCo’s total owned and purchased energy for 2013 and 2012.

PSCo also offers customer-focused renewable energy initiatives. Windsource allows customers to purchase a portion or all of their electricity from renewable sources.  In 2013, the number of customers increased to approximately 37,000 from 34,000 in 2012. Windsource MWh sales declined slightly, due in part to residential attrition, from approximately 201,000 MWh in 2012 to 197,000 MWh in 2013.  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 18,250 PV systems with approximately 188 MW of aggregate capacity and over 12,500 PV systems with approximately 138 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2013 and 2012, respectively.

Wind— PSCo acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Colorado. PSCo currently has 19 of these agreements in place, with facilities ranging in size from two MW to over 300 MW.  In October 2013, the CPUC approved the addition of 450 MW of Colorado wind generation PPAs. In addition to receiving purchased wind energy under these agreements, PSCo also typically receives wind RECs, which are used to meet state renewable resource requirements.  The average cost per MWh of wind energy under these contracts was approximately $45 and $47 for 2013 and 2012, respectively.  The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution.  Generally, contracts executed in 2013 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTC in 2013.

Additionally, PSCo owns and operates the 26 MW Ponnequin Wind Farm in northern Colorado, which has been in service since 1999. Collectively, PSCo had approximately 2,170 MW of wind energy on its system at the end of 2013 and 2012, respectively. With the new projects, PSCo is anticipated to have approximately 2,650 MW of wind power.

Wholesale Commodity Marketing Operations

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

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’s utility subsidiaries, including enforcement of NERC mandatory electric reliability standards.  State and local agencies have jurisdiction over many of PSCo’s utility subsidiaries’ activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 11 to the accompanying consolidated financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — The FERC issued Order 1000 in July 2011 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities, including RTOs, to file compliance tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area. The FERC required that the opportunity to build such projects would extend to competitive transmission developers. Colorado does not have legislation protecting ROFR rights for incumbent utilities.

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PSCo is not in an RTO and therefore is responsible for making its own Order 1000 compliance filings. PSCo submitted its compliance filing to address the regional planning and cost allocation requirements of Order 1000, proposing that PSCo would join the WestConnect region, a consortium of utilities in the Western Interconnection.  In March 2013, the FERC issued its initial order on PSCo’s compliance filing and required a further compliance filing and additional tariff changes.  In April 2013, PSCo and other WestConnect members requested rehearing on various aspects of the March 2013 order. PSCo and other WestConnect jurisdictional utilities made their compliance filings to address directives in the March 2013 order. The FERC is expected to rule in 2014 on the regional compliance filing and the requests for rehearing. WestConnect members, including PSCo, filed their Order 1000 interregional compliance filings in May 2013 and the filings are pending FERC action.

Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2013			2012			2011
Electric sales (Millions of KWh)
Residential	9,266			9,193			9,149
Large commercial and industrial	6,652			6,649			6,445
Small commercial and industrial	12,716			12,711			12,663
Public authorities and other	227			233			226
Total retail	28,861			28,786			28,483
Sales for resale	4,467			4,464			6,595
Total energy sold	33,328			33,250			35,078
Number of customers at end of period
Residential	1,187,308			1,176,356			1,166,567
Large commercial and industrial	328			334			325
Small commercial and industrial	155,643			154,575			153,111
Public authorities and other	53,724			54,396			55,547
Total retail	1,397,003			1,385,661			1,375,550
Wholesale	23			20			24
Total customers	1,397,026			1,385,681			1,375,574
Electric revenues (Thousands of Dollars)
Residential	$	1,083,928		$	1,015,497		$	1,024,051
Large commercial and industrial	437,556			401,481			421,410
Small commercial and industrial	1,218,856			1,136,636			1,180,985
Public authorities and other	52,676			49,900			46,985
Total retail	2,793,016			2,603,514			2,673,431
Wholesale	228,041			210,627			347,672
Other electric revenues	60,114			155,758			93,267
Total electric revenues	$	3,081,171		$	2,969,899		$	3,114,370
KWh sales per retail customer	20,659			20,774			20,706
Revenue per retail customer	$	1,999		$	1,879		$	1,944
Residential revenue per KWh	11.70		¢	11.05		¢	11.19		¢
Large commercial and industrial revenue per KWh	6.58			6.04			6.54
Small commercial and industrial revenue per KWh	9.59			8.94			9.33
Total retail revenue per KWh	9.68			9.04			9.39
Wholesale revenue per KWh	5.11			4.72			5.27

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Energy Source Statistics

	Year Ended Dec. 31
	2013			2012			2011
	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	19,647	56	%	21,367	59	%	22,065	61	%
Natural Gas	7,565	22		7,930	22		8,896	24
Wind (a)	6,750	19		5,752	16		4,518	12
Hydroelectric	655	2		590	2		681	2
Other (b)	250	1		263	1		324	1
Total	34,867	100	%	35,902	100	%	36,484	100	%
Owned generation	22,873	66	%	23,766	66	%	23,743	65	%
Purchased generation	11,994	34		12,136	34		12,741	35
Total	34,867	100	%	35,902	100	%	36,484	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) Includes energy from other sources, including solar, biomass, oil and refuse.  Distributed generation from the Solar*Rewards program is not included, and was approximately 0.172, 0.133, and 0.137 net million KWh for 2013, 2012, and 2011, respectively.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of PSCo are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per customer, as a result of improved building construction technologies, higher appliance efficiencies, and conservation.  From 2000 to 2013, average annual sales to the typical PSCo residential customer declined 15 percent and 16 percent 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.

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The Pipeline and Hazardous Materials Safety Administration

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

Public Utility Regulation

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

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

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

• DSMCA — The DSMCA is a low-income energy assistance program.  The costs of this energy conservation and weatherization program are recovered through the gas DSMCA.

• PSIA — Effective Jan. 1, 2012, the PSIA began to recover costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. Although PSCo had proposed to include the PSIA in base rates, instead the rider was extended through Dec. 31, 2015.

QSP Requirements — The CPUC established a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service.  The CPUC conducts proceedings to review and approve the rate adjustment annually.In 2013, the CPUC extended the terms of the current QSP through the end of 2015.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation to be 1,952,939 MMBtu.  In addition, firm transportation customers hold 797,329 MMBtu of capacity for PSCo without supply backup.  Total firm delivery obligation for PSCo is 2,750,268 MMBtu per day.  The maximum daily deliveries for PSCo for firm and interruptible services were 1,865,207 MMBtu on Dec. 5, 2013 and 1,539,864 MMBtu on Dec. 19, 2012.

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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 1,822,939 MMBtu per day, which includes 859,514 MMBtu of natural gas held under third-party underground storage agreements.  In addition, PSCo operates three company-owned underground storage facilities, which provide approximately 22,400 MMBtu of natural gas supplies on a peak day.  The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo’s city gate meter stations.

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

Natural Gas Supply and Costs

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

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

2013	$	4.20
2012	4.28
2011	4.99

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, 2013, PSCo was committed to approximately $2.0 billion in such obligations under these contracts, which expire in various years from 2014 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 2013, PSCo purchased natural gas from approximately 40 suppliers.

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

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Natural Gas Operating Statistics

	Year Ended Dec. 31
	2013		2012		2011
Natural gas deliveries (Thousands of MMBtu)
Residential	100,329		85,280		94,947
Commercial and industrial	40,259		34,597		38,433
Total retail	140,588		119,877		133,380
Transportation and other	109,637		101,490		102,874
Total deliveries	250,225		221,367		236,254
Number of customers at end of period
Residential	1,228,917		1,217,972		1,209,210
Commercial and industrial	100,071		100,110		100,329
Total retail	1,328,988		1,318,082		1,309,539
Transportation and other	6,273		5,746		5,356
Total customers	1,335,261		1,323,828		1,314,895
Natural gas revenues (Thousands of Dollars)
Residential	$	729,304	$	650,107	$	746,133
Commercial and industrial	273,032		241,777		277,962
Total retail	1,002,336		891,884		1,024,095
Transportation and other	78,367		70,551		63,654
Total natural gas revenues	$	1,080,703	$	962,435	$	1,087,749
MMBtu sales per retail customer	105.79		90.95		101.85
Revenue per retail customer	$	754	$	677	$	782
Residential revenue per MMBtu	7.27		7.62		7.86
Commercial and industrial revenue per MMBtu	6.78		6.99		7.23
Transportation and other revenue per MMBtu	0.71		0.70		0.62

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

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Competition

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

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 new electric transmission facilities. PSCo also has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew a franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. Several states, including Colorado, have policies designed to promote the development of solar and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to Xcel Energy’s electric service business. These competitive challenges continue to evolve over time. While facing these challenges, PSCo believes its rates and services are competitive with currently available alternatives. PSCo continues to evaluate policies, products and strategies to enable it to compete in the changing energy marketplace.

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. PSCo strives to comply with all environmental regulations applicable to its operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon PSCo’s operations. See Notes 11 and 12 to the consolidated financial statements for further discussion.

There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. While environmental regulations related to climate change and clean energy continue to evolve, 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. Although the impact of these policies on PSCo will depend on the specifics of state and federal policies, legislation, and regulation, we believe that, based on prior state commission practice, we would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2013, PSCo had 2,762 full-time employees and two part-time employees, of which 2,086 were covered under collective-bargaining agreements. See Note 8 to the consolidated financial statements for further discussion.

Item 1A — Risk Factors

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

There may be further risks and uncertainties that are not presently known or are not currently believed to be material that may adversely affect our performance or financial condition in the future.

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Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes PSCo, is to understand, manage and, when possible, mitigate material risk. Management is responsible for identifying and managing risks, while the Board of Directors oversees and holds management accountable.  PSCo is faced with a number of different types of risk.  Many of these risks are cross-cutting risks such that these risks are discussed and managed across business areas and coordinated by Xcel Energy Inc.’s and PSCo’s senior management. Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.

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

Management seeks to mitigate the risks inherent in the implementation of Xcel Energy Inc.’s and PSCo’s strategy.  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.  At a threshold level, we have developed a robust compliance program and promote a culture of compliance, including tone at the top, which mitigates risk.  Building on this culture of compliance, we manage and further mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of corporate areas such as internal audit, the corporate controller and legal services.  While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

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

The guidelines on corporate governance and Board committee charters define the scope of review and inquiry for the Board and its committees. Each Board committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. Xcel Energy Inc.’s Board of Directors has overall responsibility for risk oversight and with the committees periodically undertakes the review of the charters to ensure that oversight of key risks are appropriately considered by the various Board committees. Xcel Energy Inc.’s Board also reviews risks at an enterprise level and annually conducts a full day strategy session where it considers risks and confirms that Xcel Energy’s and PSCo's strategy appropriately addresses risk management and mitigation and reviews the performance and annual goals of each business area.

As described above, the Board reviews senior management’s key risk assessment that analyzes the most likely areas of future risk to Xcel Energy. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy. The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.

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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, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance no longer makes operation of the units economic. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We may be required to pay all or a portion of the cost to remediate (i.e., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2013, 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.  These mandates are designed in part to mitigate the potential environmental impacts of utility operations.  Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial position or cash flows.

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

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events.  We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.

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 depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

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

To the extent climate change impacts a region’s economic health, it may also impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as a tax on GHGs 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.

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

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

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.  For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchased power contracts.  An increase in the overall level of capacity payments would increase the amount of our imputed debt, based on Standard & Poor’s methodology.  Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchased power contracts or changes in how imputed debt is determined. 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 in property, plant and equipment; consequently, we are an active participant in debt and equity markets.  Any disruption in capital markets could have a material impact on our ability to fund our operations.  Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy.  Capital market disruption events and resulting broad financial market distress, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

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

We are subject to credit risks.

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

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity: however, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant.  The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception. In addition, the CFTC has granted an increase in the de minimis level for swap transactions with defined utility special entities, generally entities owning or operating electric or natural gas facilities, from $25 million to $800 million.  Our current level of financial swap activity with special entities is significantly below this new threshold; therefore, we will not be classified as a swap dealer in our special entity activity.  Swap transactions with non special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act.  We are currently reporting all of our swap transactions as part of the Dodd-Frank Act.

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

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

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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 substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations.  In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans with modifications to these funding requirements that allowed additional flexibility in the timing of contributions.  Therefore, our funding requirements and related contributions may change in the future.  Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

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

Our self-insured costs of health care benefits for eligible employees and costs for retiree health care plans have increased substantially 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.  Legislation related to health care could also significantly change our benefit programs and costs.

Operational Risks

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. As a result we are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility.  Actual settlements can vary significantly from these estimates, 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 customers at previously authorized or anticipated costs.  Any such disruption, if significant, would cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers.  The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, natural gas pipeline capacity, etc.

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

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

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

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

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

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

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

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

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

As of Dec. 31, 2013, Xcel Energy Inc. and its utility subsidiaries had approximately $10.9 billion of long-term debt and $1.0 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, 2013, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19.4 million and $0.3 million of exposure. Xcel Energy also had additional guarantees of $32.1 million at Dec. 31, 2013 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.

21

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 2013, 2012 and 2011 we paid $263.9 million, $267.0 million and $270.1 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. PSCo’s most restrictive dividend limitation is imposed by its credit facility, which limits the debt-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  The U.S. continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change.  Such 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 regulation under climate change laws at either the state or federal level in the future. The EPA is regulating GHGs under the CAA. The EPA has regulated GHG emissions from motor vehicles and adopted new permitting requirements for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has proposed regulations that would establish NSPS for any new fossil fuel-fired power plants that may be built. If adopted, these regulations could significantly increase the cost of building new generating plants. By 2016, the EPA plans to develop and implement GHG regulations applicable to emissions from existing power plants. Such regulations could impose substantial costs on our system.

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.

There are many uncertainties regarding when and in what form climate change legislation or regulations may be enacted.  The impact of legislation and regulations will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are recognized as compliance options, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations.  Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.  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, ash management and cooling water intake systems.  The costs of investment to comply with these rules could be substantial.  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 $1 million per violation per day.  In addition, NERC electric reliability standards are now mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations.  If a serious reliability incident did occur, it could have a material effect on our operations or financial results.

22

The FERC issued NOVs of its market manipulation rules to several market participants during 2013.  The potential penalties in one pending case exceed $400 million.  We attempt to mitigate this risk through formal training on such prohibited practices and a compliance function that reviews our interaction with the markets under FERC and CFTC jurisdictions.  However, there is no guarantee our compliance program will be sufficient to ensure against violations.

Macroeconomic Risks

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged economic recession and uncertainty of recovery has lowered the correlation between sales and economic growth. Sales growth has been relatively flat due to lower level of economic activity, increased focus on energy efficiency and distributed generation. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail 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 that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business.  We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel.  We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

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

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

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

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

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

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems (e.g., information about our customers, employees, operations, infrastructure and assets) could be directly or indirectly affected by unintentional or deliberate 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 or of our third party service providers’ operations, could also negatively impact our business.  In addition, we also anticipate that such an event would receive regulatory scrutiny at both the Federal and State level.  We are unable to quantify the potential impact of such 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.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful.  In addition, higher fuel costs could reduce customer demand and/or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

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

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

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

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

Electric Utility Generating Stations:
Station, Location and Unit	Fuel	Installed	Summer 2013 Net Dependable Capability (MW)
Steam:
Cherokee-Denver, Colo., 2 Units	Coal	1957-1968	504	(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	237	(d)
Pawnee-Brush, Colo., 1 Unit	Coal	1981	505
Valmont-Boulder, Colo., 1 Unit	Coal	1964	184
Zuni-Denver, Colo., 1 Unit	Coal	1948-1954	59
Combustion Turbine:
Blue Spruce-Aurora, Colo., 2 Units	Natural Gas	2003	264
Fort St. Vrain-Platteville, Colo., 6 Units	Natural Gas	1972-2009	969
Rocky Mountain-Keenesburg, Colo., 3 Units	Natural Gas	2004	580
Various locations, 6 Units	Natural Gas	Various	172
Hydro:
Cabin Creek-Georgetown, Colo.
Pumped Storage, 2 Units	Hydro	1967	210
Various locations, 9 Units	Hydro	Various	26
Wind:
Ponnequin-Weld County, Colo., 37 Units	Wind	1999-2001	25	(e)
		Total	4,978

^(a) Cherokee Unit 2 was taken out of service in October 2011.  Cherokee Unit 1 was taken out of service in May 2012.

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

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

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

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

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2013:

Conductor Miles
345 KV	2,157
230 KV	12,153
138 KV	92
115 KV	4,893
Less than 115 KV	74,610

PSCo had 230 electric utility transmission and distribution substations at Dec. 31, 2013.

Natural gas utility mains at Dec. 31, 2013:

Miles
Transmission	2,252
Distribution	21,718

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.

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The dividends declared during 2013 and 2012 were as follows:

(Thousands of Dollars)	2013		2012
First quarter	$	66,678	$	67,077
Second quarter	65,461		66,498
Third quarter	65,000		66,469
Fourth quarter	65,134		66,804

Item 6 — Selected Financial Data

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

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on PSCo’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the accompanying consolidated financial statements and related notes to the consolidated financial statements.

Forward-Looking Statements

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

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

Results of Operations

PSCo’s net income was approximately $453 million for 2013, compared with approximately $458 million for 2012.  The decrease is mainly due to higher depreciation, O&M expenses and customer refunds related primarily to the 2013 electric earnings test refund obligation, as well as a 2012 tax benefit associated with federal subsidies for prescription drug plans. These factors were partially offset by electric rate increases, the impact of cooler weather on natural gas margins and lower interest charges.

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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)	2013			2012
Electric revenues	$	3,081		$	2,970
Electric fuel and purchased power	(1,336		)	(1,235		)
Electric margin	$	1,745		$	1,735

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)	2013 vs. 2012
Fuel and purchased power cost recovery	$	94
Retail rate increases	35
Non-fuel riders	19
DSM program revenue	16
Transmission revenue	6
Retail sales growth	6
PSCo earnings test refund obligation	(43		)
Estimated impact of weather	(14		)
DSM program incentives	(11		)
Other, net	3
Total increase in electric revenues	$	111

Electric Margin

(Millions of Dollars)	2013 vs. 2012
Retail rate increases	$	35
Non-fuel riders	19
DSM program revenue	16
Transmission revenue, net of costs	10
Retail sales growth	6
PSCo earnings test refund obligation	(43		)
Estimated impact of weather	(14		)
DSM program incentives	(11		)
Trading margin	(4		)
Other, net	(4		)
Total increase in electric margin	$	10

Natural Gas Revenues and Margin

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

(Millions of Dollars)	2013			2012
Natural gas revenues	$	1,081		$	962
Cost of natural gas sold and transported	(621		)	(532		)
Natural gas margin	$	460		$	430

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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)	2013 vs. 2012
Purchased natural gas adjustment clause recovery	$	91
Estimated impact of weather	16
Retail rate increase	12
Retail sales growth	4
Other, net	(4		)
Total increase in natural gas revenues	$	119

Natural Gas Margin

(Millions of Dollars)	2013 vs. 2012
Estimated impact of weather	$	16
Retail rate increase	12
Retail sales growth	4
Other, net	(2		)
Total increase in natural gas margin	$	30

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased by $19.3 million, or 2.6 percent, for 2013 compared with the same period in 2012.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2013 vs. 2012
Electric and gas distribution expenses	$	34
Plant generation costs	9
Transmission costs	6
SmartGridCity	(11		)
Pipeline system integrity costs	(10		)
Employee benefits	(8		)
Other, net	(1		)
Total increase in O&M expenses	$	19

• Electric and gas distribution expenses were primarily driven by increased maintenance activities due to vegetation management, storms and outages;

• Higher plant generation costs are primarily attributable to more plant overhauls occurring in 2013;

• See Note 11 to the consolidated financial statements for further discussion of SmartGridCity;

• Lower pipeline system integrity costs relate to increased compliance and inspection initiatives in 2012; and

DSM Program Expenses— DSM program expenses increased $16.1 million, or 13.1 percent, for 2013 compared with 2012.  The higher expense is primarily attributable to an increase in the electric rate used to recover program expenses.  DSM program expenses are recovered concurrently through riders and base rates.

Depreciation and Amortization— Depreciation and amortization expense increased by approximately $21.6 million, or 6.4 percent, for 2013 compared with 2012.  The increase is primarily attributable to normal system expansion.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased by $5.9 million, or 4.5 percent, for 2013 compared with 2012. The increase is primarily due to higher property taxes.

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AFUDC— AFUDC increased by $21.1 million for 2013 compared with 2012.  The increase is primarily due to construction related to the CACJA.

Interest Charges —Interest charges decreased by $14.5 million, or 7.7 percent, for 2013 compared with 2012.  The decrease is primarily due to refinancings at lower interest rates, partially offset by higher long-term debt levels.

Income Taxes — Income tax expense increased $18.2 million for 2013 compared with 2012.  The increase in income tax expense was primarily due to higher pretax earnings in 2013 and a tax benefit recorded in 2012 related to the restoration of a portion of a tax benefit written off in 2010 associated with federal subsidies for prescription drug plans. These were partially offset in 2013 by recognition of research and experimentation credits and increased permanent plant-related adjustments.  The ETR was 35.6 percent 2013 compared with 33.7 percent for 2012. The ETR would have been 36.1 percent for 2012 without the 2012 tax benefit.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, PSCo is exposed to a variety of market risks.  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.

Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments.  PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

At Dec. 31, 2013, 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	$	318	$	—	$	—	$	—	$	318

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

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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)	2013			2012
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	792		$	1,264
Contracts realized or settled during the period	4,986			(1,358		)
Commodity trading contract additions and changes during the period	(5,460		)	886
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	318		$	792

At Dec. 31, 2013 and 2012, a 10 percent increase or decrease in market prices for commodity trading contracts would have an immaterial impact on pretax income from continuing operations.

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

(Millions of Dollars)	Year Ended Dec. 31		VaR Limit		Average		High		Low
2013	$	0.29	$	3.00	$	0.41	$	1.65	$	< 0.01
2012	0.45		3.00		0.36		1.56			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.

In conjunction with the PSCo debt issuance in September 2012, PSCo settled interest rate hedging instruments with a notional amount of $250 million with cash payments of $44.7 million.  This loss is classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and is being reclassified to earnings over the term of the hedged interest payments.  See Note 4 to the consolidated financial statements for further discussion of long-term borrowings.

At Dec. 31, 2013, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would have no impact on pretax interest expense, and at Dec. 31, 2012 a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense by approximately $1.5 million annually. See Note 10 to the consolidated financial statements for a discussion of PSCo’s interest rate derivatives.

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

At Dec. 31, 2013, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $9.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $1.4 million.  At Dec. 31, 2012, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $1.3 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $0.9 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.

30

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, 2013.  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, 2013.

Commodity derivative assets and liabilities assigned to Level 3 typically consist of forwards and options that are long-term in nature. Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers.  When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3.  There were no Level 3 commodity derivative assets or liabilities at Dec. 31, 2013.

Item 8 — Financial Statements and Supplementary Data

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

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

31

Management Report on Internal Controls Over Financial Reporting

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

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

PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2013. 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 (1992). Based on our assessment, we believe that, as of Dec. 31, 2013, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ DAVID L. EVES	/s/ TERESA S. MADDEN
David L. Eves	Teresa S. Madden
President, Chief Executive Officer and Director	Senior Vice President, Chief Financial Officer and Director
Feb. 24, 2014	Feb. 24, 2014

32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Public Service Company of Colorado

We have audited the accompanying consolidated balance sheets and statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2013 and 2012, 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, 2013.  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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2014

33

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2013			2012			2011
Operating revenues
Electric	$	3,081,171		$	2,969,899		$	3,114,370
Natural gas	1,080,703			962,435			1,087,749
Steam and other	40,754			36,959			38,683
Total operating revenues	4,202,628			3,969,293			4,240,802
Operating expenses
Electric fuel and purchased power	1,335,818			1,235,343			1,425,173
Cost of natural gas sold and transported	621,120			532,417			692,096
Cost of sales — steam and other	17,039			15,438			17,552
Operating and maintenance expenses	762,322			742,975			734,729
Demand side management program expenses	139,337			123,205			115,078
Depreciation and amortization	360,417			338,827			328,582
Taxes (other than income taxes)	137,816			131,869			133,660
Total operating expenses	3,373,869			3,120,074			3,446,870
Operating income	828,759			849,219			793,932
Other income, net	3,136			4,736			7,001
Allowance for funds used during construction —  equity	33,173			16,354			7,710
Interest charges and financing costs
Interest charges — includes other financing costs of $6,866, $7,088, and $6,883, respectively	173,602			188,094			186,885
Allowance for funds used during construction — debt	(12,657		)	(8,405		)	(3,406		)
Total interest charges and financing costs	160,945			179,689			183,479
Income before income taxes	704,123			690,620			625,164
Income taxes	250,740			232,544			228,361
Net income	$	453,383		$	458,076		$	396,803

See Notes to Consolidated Financial Statements

34

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2013			2012			2011
Net income	$	453,383		$	458,076		$	396,803
Other comprehensive loss
Derivative instruments:
Net fair value increase (decrease), net of tax of $5, $(5,708) and $(11,227), respectively	9			(9,311		)	(18,328		)
Reclassification of gains to net income, net of tax of $(294), $(725) and $(922), respectively	(476		)	(1,183		)	(1,506		)
Other comprehensive loss	(467		)	(10,494		)	(19,834		)
Comprehensive income	$	452,916		$	447,582		$	376,969

See Notes to Consolidated Financial Statements

35

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2013			2012			2011
Operating activities
Net income	$	453,383		$	458,076		$	396,803
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	365,713			344,226			333,960
Demand side management program amortization	4,802			5,299			7,876
Deferred income taxes	316,253			38,092			226,555
Amortization of investment tax credits	(2,935		)	(2,957		)	(2,613		)
Allowance for equity funds used during construction	(33,173		)	(16,354		)	(7,710		)
Provision for bad debts	16,784			16,323			20,371
SmartGridCity	—			10,666			—
Net realized and unrealized hedging and derivative transactions	(3,571		)	(39,338		)	12,102
Changes in operating assets and liabilities:
Accounts receivable	5,089			(58,226		)	(22,962		)
Accrued unbilled revenues	14,707			18,920			(7,009		)
Inventories	(14,857		)	30,203			(30,939		)
Prepayments and other	(7,210		)	(3,466		)	26,152
Accounts payable	59,361			(56,176		)	40,754
Net regulatory assets and liabilities	108,400			(31,776		)	46,334
Other current liabilities	16,561			34,305			29,843
Pension and other employee benefit obligations	(48,886		)	(57,974		)	(84,181		)
Change in other noncurrent assets	3,862			(10,101		)	4,116
Change in other noncurrent liabilities	17,191			(1,267		)	(15,039		)
Net cash provided by operating activities	1,271,474			678,475			974,413
Investing activities
Utility capital/construction expenditures	(1,066,700		)	(873,383		)	(726,830		)
Allowance for equity funds used during construction	33,173			16,354			7,710
Investments in utility money pool arrangement	(1,495,000		)	(1,000,000		)	(609,300		)
Repayments from utility money pool arrangement	1,423,000			1,052,000			557,300
Net cash used in investing activities	(1,105,527		)	(805,029		)	(771,120		)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(154,000		)	154,000			(269,400		)
Borrowings under utility money pool arrangement	14,000			36,000			203,800
Repayments under utility money pool arrangement	(14,000		)	(36,000		)	(203,800		)
Proceeds from issuance of long-term debt	492,313			790,379			246,305
Repayments of long-term debt, including reacquisition premiums	(250,000		)	(648,750		)	—
Capital contributions from parent	25,621			99,283			60,800
Dividends paid to parent	(263,942		)	(266,971		)	(270,147		)
Net cash (used in) provided by financing activities	(150,008		)	127,941			(232,442		)
Net change in cash and cash equivalents	15,939			1,387			(29,149		)
Cash and cash equivalents at beginning of period	5,150			3,763			32,912
Cash and cash equivalents at end of period	$	21,089		$	5,150		$	3,763
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(155,457	)	$	(179,610	)	$	(172,266	)
Cash received (paid) for income taxes, net	34,946			(179,321		)	28,525
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	142,103		$	94,288		$	59,094

See Notes to Consolidated Financial Statements

36

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	Dec. 31
	2013			2012
Assets
Current assets
Cash and cash equivalents	$	21,089		$	5,150
Accounts receivable, net	328,675			277,461
Accounts receivable from affiliates	19,136			93,544
Investments in utility money pool arrangement	72,000			—
Accrued unbilled revenues	270,917			285,624
Inventories	238,007			223,794
Regulatory assets	150,163			143,689
Deferred income taxes	87,267			—
Derivative instruments	6,576			4,889
Prepayments and other	32,629			22,970
Total current assets	1,226,459			1,057,121
Property, plant and equipment, net	10,742,397			10,030,991
Other assets
Regulatory assets	826,037			934,728
Derivative instruments	6,905			10,868
Other	52,520			50,461
Total other assets	885,462			996,057
Total assets	$	12,854,318		$	12,084,169
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	282,143		$	256,297
Short-term debt	—			154,000
Accounts payable	451,243			359,969
Accounts payable to affiliates	45,902			30,001
Regulatory liabilities	79,499			33,723
Taxes accrued	154,194			153,614
Accrued interest	48,492			48,014
Dividends payable to parent	65,134			66,803
Derivative instruments	6,734			8,753
Other	89,571			72,669
Total current liabilities	1,222,912			1,183,843
Deferred credits and other liabilities
Deferred income taxes	2,206,179			1,782,828
Deferred investment tax credits	39,230			42,097
Regulatory liabilities	424,690			417,404
Asset retirement obligations	60,398			43,751
Derivative instruments	23,366			30,605
Customer advances	251,062			229,498
Pension and employee benefit obligations	167,127			324,625
Other	66,855			69,307
Total deferred credits and other liabilities	3,238,907			2,940,115
Commitments and contingencies
Capitalization
Long-term debt	3,590,500			3,374,476
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2013 and 2012, respectively	—			—
Additional paid in capital	3,441,290			3,415,669
Retained earnings	1,384,047			1,192,937
Accumulated other comprehensive loss	(23,338		)	(22,871		)
Total common stockholder’s equity	4,801,999			4,585,735
Total liabilities and equity	$	12,854,318		$	12,084,169

See Notes to Consolidated Financial Statements

37

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

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

	Common Stock Issued								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2010	100	$	—	$	3,255,586	$	875,151		$	7,457		$	4,138,194
Net income						396,803						396,803
Other comprehensive loss									(19,834		)	(19,834		)
Common dividends declared to parent						(270,245		)				(270,245		)
Contribution of capital by parent				60,800								60,800
Balance at Dec. 31, 2011	100	$	—	$	3,316,386	$	1,001,709		$	(12,377	)	$	4,305,718
Net income						458,076						458,076
Other comprehensive loss									(10,494		)	(10,494		)
Common dividends declared to parent						(266,848		)				(266,848		)
Contribution of capital by parent				99,283								99,283
Balance at Dec. 31, 2012	100	$	—	$	3,415,669	$	1,192,937		$	(22,871	)	$	4,585,735
Net income						453,383						453,383
Other comprehensive loss									(467		)	(467		)
Common dividends declared to parent						(262,273		)				(262,273		)
Contribution of capital by parent				25,621								25,621
Balance at Dec. 31, 2013	100	$	—	$	3,441,290	$	1,384,047		$	(23,338	)	$	4,801,999

See Notes to Consolidated Financial Statements

38

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

	Dec. 31
	2013			2012
Long-Term Debt
First Mortgage Bonds, Series due:
March 1, 2013, 4.875%	$	—		$	250,000
April 1, 2014, 5.5%	275,000			275,000
Sept. 1, 2017, 4.375% (a)	129,500			129,500
Aug. 1, 2018, 5.8%	300,000			300,000
June 1, 2019, 5.125%	400,000			400,000
Nov. 15, 2020, 3.2%	400,000			400,000
Sept. 15, 2022, 2.25%	300,000			300,000
March 15, 2023, 2.5%	250,000			—
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			—
Capital lease obligations, through 2060, 11.2% — 14.3%	179,444			185,741
Unamortized discount	(11,301		)	(9,468		)
Total	3,872,643			3,630,773
Less current maturities	282,143			256,297
Total long-term debt	$	3,590,500		$	3,374,476
Common Stockholder’s Equity
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2013 and 2012, respectively.	$	—		$	—
Additional paid-in capital	3,441,290			3,415,669
Retained earnings	1,384,047			1,192,937
Accumulated other comprehensive loss	(23,338		)	(22,871		)
Total common stockholder’s equity	$	4,801,999		$	4,585,735

^(a)  Pollution control financing.

See Notes to Consolidated Financial Statements

39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts— PSCo is principally 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, AROs, regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs.  The recorded estimates are revised when better information becomes available or when actual amounts can be determined.  Those revisions can affect operating results.

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

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

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

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

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

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

40

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

Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems.  These programs include commercial process efficiency and lighting updates, as well as rebates for participation in air conditioner interruption and energy-efficient appliances.

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of 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 and compensate for related lost sales margin.  PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

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

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period. For investments in property, plant and equipment that are 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 on abandonment is recognized, if necessary.

PSCo records depreciation expense related to its plant using the straight-line method over the plant’s useful life.  Actuarial and semi-actuarial life studies are performed on a periodic basis 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 2.8, 2.6 and 2.6 percent for the years ended Dec. 31, 2013, 2012 and 2011, respectively.

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

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

41

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

AROs— PSCo records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with the applicable accounting guidance.  This liability will be increased over time by applying the effective interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the amounts through the establishment of a regulatory asset and recovery in rates.

PSCo also recovers currently in rates certain future plant removal costs in addition to AROs and related capitalized costs, and a regulatory liability is recognized for such future expenditures.  See Note 12 for further discussion of AROs.

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

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

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

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

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

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

See Note 7 for further discussion of income taxes.

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

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

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

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

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

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

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

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

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

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

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

Inventory— All inventory is recorded at average cost.

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

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

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

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

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

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

See Note 12 for further discussion of environmental costs.

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

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

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

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

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

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 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 Adopted

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  PSCo implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 10 for the required disclosures.

Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated OCI and amounts reclassified out of accumulated OCI.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  PSCo implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 14 for the required disclosures.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	351,180		$	299,379
Less allowance for bad debts	(22,505		)	(21,918		)
	$	328,675		$	277,461

(Thousands of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	53,127	$	54,486
Fuel	86,062		89,246
Natural gas	98,818		80,062
	$	238,007	$	223,794

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(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	10,177,056		$	9,782,163
Natural gas plant	2,757,605			2,583,394
Common and other property	762,916			761,712
Plant to be retired (a)	101,279			152,730
Construction work in progress	952,469			506,225
Total property, plant and equipment	14,751,325			13,786,224
Less accumulated depreciation	(4,008,928		)	(3,755,233		)
	$	10,742,397		$	10,030,991

^(a)  As a result of the CPUC’s 2010 approval of PSCo’s CACJA compliance plan, subsequent CPCNs and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Units 1, 2 and 3, Arapahoe Units 3 and 4 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired, in 2012, Cherokee Unit 1 was retired, and in 2013, Arapahoe Units 3 and 4 were retired. 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. PSCo had no money pool borrowings outstanding during the three months ended Dec. 31, 2013. Money pool borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end	—			—			—
Average amount outstanding	0.1			0.3			3
Maximum amount outstanding	12			8			53
Weighted average interest rate, computed on a daily basis	0.36		%	0.33		%	0.35		%
Weighted average interest rate at period end	N/A			N/A			N/A

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Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. PSCo had no commercial paper borrowings outstanding during the three months ended Dec. 31, 2013. Commercial paper borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	700		$	700		$	700
Amount outstanding at period end	—			154			—
Average amount outstanding	38			8			73
Maximum amount outstanding	332			165			304
Weighted average interest rate, computed on a daily basis	0.34		%	0.33		%	0.37		%
Weighted average interest rate at period end	N/A			0.35			N/A

Letters of Credit— PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2013 and 2012, there were $6.4 million and $4.0 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.

PSCo has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $700 million and the credit facility terminates in July 2017.

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

Other features of PSCo’s credit facility include:

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

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

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

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

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

At Dec. 31, 2013, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	6.4	$	693.6

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding 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, 2013 and 2012.

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Long-Term Borrowings

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

In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023, and $250 million of 3.95 percent first mortgage bonds due March 15, 2043. In September 2012, PSCo issued $300 million of 2.25 percent first mortgage bonds due Sept. 15, 2022 and $500 million of 3.60 percent first mortgage bonds due Sept. 15, 2042.

In October 2012, PSCo redeemed $48.75 million of 5.10 percent bonds due Jan. 1, 2019.

During the next five years, PSCo has long-term debt maturities of $275 million, $130 million and $300 million due in 2014, 2017 and 2018, respectively.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $37 million and $23 million, net of amortization, at Dec. 31, 2013 and 2012, respectively.  PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

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

5. Preferred Stock

PSCo has authorized the issuance of preferred stock.

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

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6. Joint Ownership of Generation, Transmission and Gas Facilities

Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2013:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Generation:
Hayden Unit 1	$	97,879	$	63,474	$	53	75.5	%
Hayden Unit 2	119,972		57,875		5,563		37.4
Hayden Common Facilities	36,916		16,055		2		53.1
Craig Units 1 and 2	60,089		34,754		537		9.7
Craig Common Facilities 1, 2 and 3	37,177		17,247		—		6.5
Comanche Unit 3	877,489		63,963		581		66.7
Comanche Common Facilities	19,812		711		2,255		82.0
Electric Transmission:
Transmission and other facilities, including substations	150,502		59,118		827		Various
Gas Transportation:
Rifle, Colo. to Avon, Colo.	16,278		6,044		—		60.0
Total	$	1,416,114	$	319,241	$	9,818

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

7. Income Taxes

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

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

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2013, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013.  PSCo is not expected to accrue any income tax expense related to this adjustment.  Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution are uncertain.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Dec. 31, 2013, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the fourth quarter of 2013, the state of Colorado completed an examination of tax years 2006 through 2009. No material adjustments were proposed for those tax years. There are currently no other state income tax audits in progress.

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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, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	2.5	$	1.3
Unrecognized tax benefit — Temporary tax positions	5.9		8.3
Total unrecognized tax benefit	$	8.4	$	9.6

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

(Millions of Dollars)	2013			2012			2011
Balance at Jan. 1	$	9.6		$	11.4		$	11.6
Additions based on tax positions related to the current year	3.9			1.9			3.4
Reductions based on tax positions related to the current year	—			(1.5		)	(0.8		)
Additions for tax positions of prior years	3.3			2.0			5.8
Reductions for tax positions of prior years	(0.9		)	(4.2		)	(0.9		)
Settlements with taxing authorities	(7.5		)	—			(7.7		)
Balance at Dec. 31	$	8.4		$	9.6		$	11.4

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

(Millions of Dollars)	Dec. 31, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(7.0	)	$	(5.3	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2013, 2012 and 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2013, 2012 or 2011.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As PSCo had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.

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)	2013		2012
Federal NOL carryforward	$	315.5	$	264.7
Federal tax credit carryforwards	19.4		16.2
State NOL carryforwards	664.6		595.1
State tax credit carryforwards, net of federal detriment	11.2		11.6

The federal carryforward periods expire between 2021 and 2033.  The state carryforward periods expire between 2019 and 2033.

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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:

	2013		2012		2011
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	3.0		2.3		2.5
Change in unrecognized tax benefits	0.1		0.1		(0.1	)
Regulatory differences — utility plant items	(1.4	)	(0.6	)	(0.2	)
Tax credits recognized, net of federal income tax expense	(0.8	)	(0.6	)	(0.8	)
Prescription drug tax benefit and Medicare Part D	—		(2.5	)	(0.1	)
Other, net	(0.3	)	—		0.2
Effective income tax rate	35.6	%	33.7	%	36.5	%

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

(Thousands of Dollars)	2013			2012			2011
Current federal tax (benefit) expense	$	(52,408	)	$	176,354		$	1,889
Current state tax (benefit) expense	(7,252		)	24,502			(796		)
Current change in unrecognized tax (benefit) expense	(2,918		)	(3,447		)	3,326
Deferred federal tax expense	273,916			38,309			207,620
Deferred state tax expense (benefit)	38,243			(4,424		)	22,994
Deferred change in unrecognized tax expense (benefit)	4,094			4,207			(4,059		)
Deferred investment tax credits	(2,935		)	(2,957		)	(2,613		)
Total income tax expense	$	250,740		$	232,544		$	228,361

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

(Thousands of Dollars)	2013			2012			2011
Deferred tax expense excluding items below	$	335,580		$	41,233		$	216,393
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(19,616		)	(9,574		)	(1,987		)
Tax benefit allocated to other comprehensive income and other	289			6,433			12,149
Deferred tax expense	$	316,253		$	38,092		$	226,555

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

(Thousands of Dollars)	2013		2012
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,197,685	$	1,838,065
Employee benefits	100,003		99,286
Other	132,436		128,453
Total deferred tax liabilities	$	2,430,124	$	2,065,804
Deferred tax assets:
NOL carryforward	$	137,043	$	129,829
Unbilled revenue - fuel costs	49,171		54,353
Tax credit carryforward	30,643		27,752
Rate refund	26,943		4,533
Deferred investment tax credits	14,905		15,992
Regulatory liabilities	14,893		14,164
Other	37,614		35,849
Total deferred tax assets	$	311,212	$	282,472
Net deferred tax liability	$	2,118,912	$	1,783,332

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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 75 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2013, PSCo had 2,086 bargaining employees covered under a collective-bargaining agreement, which expires in May 2014.

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

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

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

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

Specific valuation methods include the following:

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

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

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

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

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

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Pension Benefits

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

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2013 and 2012 were $36.5 million and $39.4 million, respectively, of which $3.5 million and $4.1 million were attributable to PSCo. In 2013 and 2012, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6.6 million and $15.6 million, respectively, of which $0.6 million and $0.7 million were attributable to PSCo. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns were below the assumed levels of 6.47 percent in 2013 and above 6.65 and 7.00 percent in 2012 and 2011, respectively. Xcel Energy Inc. and PSCo continually review the pension assumptions. In 2014, PSCo’s expected investment-return assumption is 6.81 percent.

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

The following table presents the target pension asset allocations for PSCo:

	2013		2012
Domestic and international equity securities	29	%	20	%
Long-duration fixed income and interest rate swap securities	36		50
Short-to-intermediate term fixed income securities	14		9
Alternative investments	19		19
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.

53

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, 2013 and 2012:

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

	Dec. 31, 2012
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	49,367	$	—		$	—	$	49,367
Derivatives	—		7,190			—		7,190
Government securities	—		159,137			—		159,137
Corporate bonds	—		248,759			—		248,759
Asset-backed securities	—		—			4,604		4,604
Mortgage-backed securities	—		—			12,058		12,058
Common stock	21,560		—			—		21,560
Private equity investments	—		—			47,056		47,056
Commingled funds	—		495,697			—		495,697
Real estate	—		—			19,273		19,273
Securities lending collateral obligation and other	—		(9,393		)	—		(9,393		)
Total	$	70,927	$	901,390		$	82,991	$	1,055,308

The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

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

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

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

54

(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2011
Asset-backed securities	$	8,399	$	713		$	(744	)	$	1,456		$	—	$	9,824
Mortgage-backed securities	36,134		320			(1,774		)	(11,066		)	—		23,614
Private equity investments	36,420		1,229			3,925			7,915			—		49,489
Real estate	21,962		(190		)	6,000			(16,542		)	—		11,230
Total	$	102,915	$	2,072		$	7,407		$	(18,237	)	$	—	$	94,157

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)	2013			2012
Accumulated Benefit Obligation at Dec. 31	$	1,134,184		$	1,178,447
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,194,371		$	1,047,373
Service cost	25,206			22,719
Interest cost	46,160			51,192
Transfer from other plan	11,306			—
Plan amendments	—			626
Actuarial (gain) loss	(49,384		)	138,259
Benefit payments	(74,823		)	(65,798		)
Obligation at Dec. 31	$	1,152,836		$	1,194,371

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,055,308		$	969,207
Actual return on plan assets	30,684			110,113
Employer contributions	44,582			41,786
Transfer from other plan	11,306			—
Benefit payments	(74,823		)	(65,798		)
Fair value of plan assets at Dec. 31	$	1,067,057		$	1,055,308

(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(85,779	)	$	(139,063	)

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

(Thousands of Dollars)	2013			2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	450,202		$	509,867
Prior service credit	(21,800		)	(22,864		)
Total	$	428,402		$	487,003

(Thousands of Dollars)	2013		2012
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	$	36,271	$	33,177
Noncurrent regulatory assets	392,131		453,826
Total	$	428,402	$	487,003

Measurement date Dec. 31, 2013 Dec. 31, 2012

55

	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75
Mortality table	RP 2000		RP 2000

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. These regulations did not require cash funding for 2008 through 2010 for Xcel Energy’s pension plans. Required contributions were made in 2011, 2012 and 2013 to meet minimum funding requirements.

The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through January 2014:

• In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $35.1 million was attributable to PSCo;

• In 2013, contributions of $192.4 million were made across four of Xcel Energy’s pension plans, of which $44.6 million was attributable to PSCo;

• In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans, of which $41.8 million was attributable to PSCo;

• In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans, of which $60.5 million was attributable to PSCo;

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

Plan Amendments — Xcel Energy, which includes PSCo, amended the plan in 2012 to allow a one time transfer of a portion of qualifying obligations from the nonqualified pension plan into the qualified pension plans. Xcel Energy and PSCo also modified the benefit formula for nonbargaining and bargaining new hires beginning in 2012 to a reduced benefit level.

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

(Thousands of Dollars)	2013			2012			2011
Service cost	$	25,206		$	22,719		$	17,726
Interest cost	46,160			51,192			52,234
Expected return on plan assets	(63,821		)	(65,302		)	(67,946		)
Amortization of prior service (credit) cost	(1,064		)	228			222
Amortization of net loss	43,418			34,332			28,126
Net periodic pension cost	$	49,899		$	43,169		$	30,362

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.00	%	5.00	%	5.50	%
Expected average long-term increase in compensation level	3.75		4.00		4.00
Expected average long-term rate of return on assets	6.47		6.65		7.00

56

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 $11.6 million, $9.6 million and $6.8 million in 2013, 2012 and 2011, 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 2014 pension cost calculations is 6.81 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for PSCo was approximately $8.7 million in 2013, $8.6 million in 2012 and $8.5 million in 2011.

Postretirement Health Care Benefits

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

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

Regulatory agencies for nearly all retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs. The Colorado jurisdictional postretirement benefit costs deferred during the transition period were amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. PSCo transitioned to full accrual accounting for postretirement benefit costs between 1993 and 1997.

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. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

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. 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.

57

The following tables present, for each of the fair value hierarchy levels, PSCo’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2013 and 2012:

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

	Dec 31, 2012
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	80,852	$	—		$	—	$	80,852
Derivatives	—		4			—		4
Government securities	—		65,059			—		65,059
Insurance contracts	—		44,295			—		44,295
Corporate bonds	—		38,806			—		38,806
Asset-backed securities	—		—			670		670
Mortgage-backed securities	—		—			35,394		35,394
Commingled funds	—		202,331			—		202,331
Other	—		(41,494		)	—		(41,494		)
Total	$	80,852	$	309,001		$	36,064	$	425,917

The following tables present the changes in PSCo’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

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

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

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

58

(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2011
Asset-backed securities	$	2,427	$	(8	)	$	(979	)	$	5,501		$	—	$	6,941
Mortgage-backed securities	17,461		(1,469		)	1,714			6,332			—		24,038
Private equity investments	1,018		12			9			(560		)	—		479
Real estate	614		(2		)	206			(674		)	—		144
Total	$	21,520	$	(1,467	)	$	950		$	10,599		$	—	$	31,602

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

(Thousands of Dollars)	2013			2012
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	599,831		$	507,734
Service cost	2,564			2,825
Interest cost	22,210			24,527
Medicare subsidy reimbursements	923			2,185
Plan amendments	(14,571		)	(1,541		)
Plan participants’ contributions	4,589			4,042
Actuarial (gain) loss	(76,889		)	92,694
Benefit payments	(29,686		)	(32,635		)
Obligation at Dec. 31	$	508,971		$	599,831

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	425,917		$	376,508
Actual return on plan assets	30,390			50,473
Plan participants’ contributions	4,589			4,042
Employer contributions	6,983			27,529
Benefit payments	(29,686		)	(32,635		)
Fair value of plan assets at Dec. 31	$	438,193		$	425,917

(Thousands of Dollars)	2013			2012
Funded Status at Dec. 31:
Funded status (a)	$	(70,778	)	$	(173,914	)

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

(Thousands of Dollars)	2013			2012
Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	107,232		$	198,983
Prior service credit	(46,436		)	(39,531		)
Transition obligation	—			785
Total	$	60,796		$	160,237

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	8,798	$	4,597
Noncurrent regulatory assets	51,998		155,640
Total	$	60,796	$	160,237

Measurement date Dec. 31, 2013 Dec. 31, 2012

59

	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.82	%	4.10	%
Mortality table	RP 2000		RP 2000
Health care costs trend rate — initial	7.00	%	7.50	%

Effective Jan. 1, 2014, the initial medical trend rate was decreased from 7.5 percent to 7.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is five 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	$	52,619	$	(44,089	)
Service and interest components	2,448		(1,933		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes PSCo, contributed $17.6 million, $47.1 million and $49.0 million during 2013, 2012 and 2011, respectively, of which $7.0 million, $27.5 million and $28.8 million were attributable to PSCo. Xcel Energy expects to contribute approximately $13.3 million during 2014, of which amounts attributable to PSCo will be zero.

Plan Amendments — The 2013 decrease of the projected Xcel Energy and PSCo postretirement health and welfare benefit obligation for plan amendments is due to changes in the participant co-pay structure for certain retiree groups. The 2012 decrease of the projected Xcel Energy and PSCo postretirement health and welfare benefit obligation for plan amendments is due to the expected transition of certain participant groups to an external plan administrator.

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

(Thousands of Dollars)	2013			2012			2011
Service cost	$	2,564		$	2,825		$	3,625
Interest cost	22,210			24,527			28,391
Expected return on plan assets	(29,227		)	(25,056		)	(27,961		)
Amortization of transition obligation	785			11,004			11,004
Amortization of prior service credit	(7,666		)	(5,150		)	(2,913		)
Amortization of net loss	13,699			10,930			8,942
Net periodic postretirement benefit cost	$	2,365		$	19,080		$	21,088
Additional cost recognized due to effects of regulation	—			3,891			3,891
Net benefit cost recognized for financial reporting	$	2,365		$	22,971		$	24,979

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.10	%	5.00	%	5.50	%
Expected average long-term rate of return on assets	7.11		6.75		7.50

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.

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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
2014	$	77,490	$	36,778	$	2,396	$	34,382
2015	78,297		38,061		2,564		35,497
2016	80,894		39,418		2,715		36,703
2017	81,037		40,135		2,881		37,254
2018	84,004		42,019		3,042		38,977
2019-2023	430,547		206,729		17,204		189,525

9. Other Income, Net

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

(Thousands of Dollars)	2013			2012			2011
Interest income	$	1,761		$	3,603		$	4,860
Other nonoperating income	2,603			2,233			2,512
Insurance policy expense	(1,228		)	(1,100		)	(359		)
Other nonoperating expense	—			—			(12		)
Other income, net	$	3,136		$	4,736		$	7,001

10. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2.  When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

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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, 2013, accumulated other comprehensive losses related to interest rate derivatives included $0.5 million of net gains 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.

In conjunction with the PSCo debt issuance in September 2012, PSCo settled interest rate hedging instruments with a notional amount of $250 million with cash payments of $44.7 million.  This loss is classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and is being reclassified to earnings over the term of the hedged interest payments.  See Note 4 for further discussion of long-term borrowings.

Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments.  PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes.  This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel.

At Dec. 31, 2013, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016.  PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2013 and 2012.

At Dec. 31, 2013, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

The following table details the gross notional amounts of commodity forwards and options at Dec. 31, 2013 and 2012:

(Amounts in Thousands)(a)(b)	Dec. 31, 2013	Dec. 31, 2012
MWh of electricity	326	813
MMBtu of natural gas	6,398	646
Gallons of vehicle fuel	217	307

^(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.

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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, 2013, five of PSCo’s 10 most significant counterparties for these activities, comprising $35.2 million or 36 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  The remaining five significant counterparties, comprising $35.9 million or 36 percent of this credit exposure at Dec. 31, 2013, were not rated by these agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.  All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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

(Thousands of Dollars)	2013			2012			2011
Accumulated other comprehensive (loss) income related to cash flow hedges at Jan. 1	$	(22,871	)	$	(12,377	)	$	7,457
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	9			(9,311		)	(18,328		)
After-tax net realized gains on derivative transactions reclassified into earnings	(476		)	(1,183		)	(1,506		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23,338	)	$	(22,871	)	$	(12,377	)

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2013, 2012 and 2011, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

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

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

	Year Ended Dec. 31, 2011
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(29,630	)	$	—		$	(2,337	)	(a)	$	—		$	—
Vehicle fuel and other commodity	76			—			(92		)	(b)	—			—
Total	$	(29,554	)	$	—		$	(2,429	)		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—		$	88		(c)
Natural gas commodity	—			(85,357		)	—				70,811		(e)	(382		)	(d)
Total	$	—		$	(85,357	)	$	—			$	70,811		$	(294	)

^(a)  Amounts are recorded to interest charges.

^(b)  Amounts are recorded to O&M expenses.

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

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

^(e)  Amounts for the years ended Dec. 31, 2012 and 2011 included $5.0 million and $12.7 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.  Such losses for the year ended Dec. 31, 2013 were immaterial.  The remaining settlement losses for the years ended Dec. 31, 2013, 2012 and 2011 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, 2013, 2012 and 2011.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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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.  If the credit ratings of PSCo were downgraded below investment grade, derivative instruments reflected in a $1.4 million and $4.6 million gross liability position on the consolidated balance sheets at Dec. 31, 2013 and 2012, respectively, would have required PSCo to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $1.4 million and $4.6 million at Dec. 31, 2013 and 2012, respectively. At Dec. 31, 2013 and 2012, there was no collateral posted on these specific contracts.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses.  These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired.  PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2013 and 2012.

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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, 2013:

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

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, PSCo qualified these contracts under the normal purchase exception.  Based 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, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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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, 2012:

	Dec. 31, 2012
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	43	$	—	$	43	$	—		$	43
Other derivative instruments:
Commodity trading	—		6,432		—		6,432		(3,301		)	3,131
Natural gas commodity	—		7		—		7		(7		)	—
Total current derivative assets	$	—	$	6,482	$	—	$	6,482	$	(3,308	)	3,174
PPAs (a)												1,715
Current derivative instruments												$	4,889
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	39	$	—	$	39	$	—		$	39
Other derivative instruments:
Commodity trading	—		3,768		—		3,768		(1,546		)	2,222
Total noncurrent derivative assets	$	—	$	3,807	$	—	$	3,807	$	(1,546	)	2,261
PPAs (a)												8,607
Noncurrent derivative instruments												$	10,868
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	5,958	$	—	$	5,958	$	(2,712	)	$	3,246
Natural gas commodity	—		85		—		85		(7		)	78
Total current derivative liabilities	$	—	$	6,043	$	—	$	6,043	$	(2,719	)	3,324
PPAs (a)												5,429
Current derivative instruments												$	8,753
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	3,450	$	—	$	3,450	$	(1,546	)	$	1,904
Total noncurrent derivative liabilities	$	—	$	3,450	$	—	$	3,450	$	(1,546	)	1,904
PPAs (a)												28,701
Noncurrent derivative instruments												$	30,605

^(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, 2012.  At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and no rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2013, 2012 and 2011.

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, 2013, 2012 and 2011.

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Fair Value of Long-Term Debt

As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2013				2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,872,643	$	4,059,661	$	3,630,773	$	4,131,866

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, 2013 and 2012, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

11. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — CPUC

2013 Gas Rate Case —In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015.  The request was based on a 2013 FTY, a 10.5 percent ROE, a rate base of $1.3 billion and an equity ratio of 56 percent.  PSCo requested an extension of its PSIA rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects. PSCo estimated that the PSIA would increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue.  Interim rates, subject to refund, went into effect in August 2013.

In April 2013, several parties filed testimony. PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, with subsequent step increases of $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. This requested increase includes amounts to be transferred from the PSIA rider mechanism. The deficiency, based on an FTY, was $30.6 million.

In December 2013, the CPUC approved a natural gas base rate increase of approximately $15.8 million based on an ROE of 9.72 percent, a HTY with an end of year rate base and an equity ratio of 56 percent. As of Dec. 31, 2013, PSCo accrued revenue subject to refund of approximately $20.9 million.

While the CPUC rejected PSCo’s request of an FTY and multi-year rate plan, they made clear they supported the benefits that rate certainty brings to customers and PSCo. The CPUC did not reverse the ALJ’s failure to approve expansion and acceleration of PSCo’s pipeline integrity projects. However, the CPUC discussed the importance of pipeline integrity and safety matters and extended the PSIA recovery mechanism for one year to allow for PSCo to file an application for full consideration of all new projects and acceleration.

The following table summarizes the CPUC decision:

(Millions of Dollars)	CPUC Decision
PSCo deficiency based on a FTY	$	44.8
HTY adjustment	(5.4		)
ROE and capital structure adjustments	(8.3		)
Revenue adjustments	(1.4		)
Other	(0.1		)
Recommendation	29.6
Neutralize PSIA - base rate transfer	(13.8		)
Incremental base revenue	$	15.8

Rates and conforming changes made to the PSIA were effective Jan. 1, 2014.

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2013 Steam Rate Case —In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015.  The request was based on a 2013 FTY, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent.

In October 2013, PSCo, the CPUC Staff, the OCC and Colorado Energy Consumers filed a comprehensive settlement, which tied the outcome of the steam rate case to key issues to be decided in the natural gas rate case, including ROE and capital structure. The settlement allowed the filed rates to be effective on Jan. 1, 2014, subject to refund, resulting in a minimum 2014 annual rate increase of $1.2 million. The settlement also withdrew the rate relief request for 2015 without prejudice to PSCo seeking prospective rate relief at any time through the filing of a future steam case. In November 2013, the settlement became final. Final rates were implemented on Feb. 1, 2014.

Annual Electric Earnings Test — An earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year over PSCo’s authorized ROE threshold of 10 percent.  In June 2013, PSCo entered into a comprehensive settlement of issues with all parties associated with the 2012 earnings test, resulting in a refund obligation of approximately $8.2 million to be refunded through June 2014. As of Dec. 31, 2013, PSCo has also recognized management’s best estimate of an accrual for the 2013 test year.

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

ECA Prudence Review — In September 2013, the CPUC Staff requested that the 2012 annual ECA prudence review be set for hearing. The prudence review, as determined by the ALJ, will primarily consider if replacement power costs during the outage of jointly owned facilities were properly allocated between wholesale and retail customers.

2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report. The OCC and CPUC Staff requested the CPUC set the matter for hearing to review in detail the information provided, including a review of the prudence of expenditures in 2012, and to develop standards for future filings. In July 2013, the CPUC approved the request and assigned the matter to an ALJ.

In January 2014, the CPUC Staff recommended a disallowance of $3.7 million of capital expenditures related to a pipeline replacement project and a disallowance related to an inspection program. Collectively, these represent approximately $0.6 million of disallowances related to 2012 revenue requirements. On Feb. 6, 2014, PSCo filed rebuttal testimony addressing the CPUC Staff’s recommended disallowances.

Next steps in the procedural schedule are as follows:

• Evidentiary hearing — March 3 - March 7, 2014;

• Initial brief — March 28, 2014; and

• Reply brief — April 11, 2014.

Electric, Purchased Gas and Resource Adjustment Clauses

DSM and the DSMCA — The CPUC approved higher savings goals and a slightly higher financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2012.  Savings goals are 356 GWh in 2013 and 384 GWh in 2014 with incentives awarded in the year following plan achievements.  PSCo is able to earn an incentive on 11 percent of net economic benefits and a maximum annual incentive of $30 million.

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The CPUC approved the PSCo electric and gas DSM budget of $115.5 million and $13.3 million, respectively, effective Jan. 1, 2013. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates.  Electric DSMCA rates are designed to collect $26.8 million in 2013 with the remainder of the electric DSM expenditures collected through base rates. PSCo filed its 2014 DSM plan in July 2013 and reached a settlement with all but one party. Hearings were held in December 2013 seeking approval of a 2014 DSM electric budget of $87.8 million and a gas budget of $12.3 million. A decision by the ALJ is anticipated by the end of the first quarter of 2014.  DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year.

REC Sharing — In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014.  The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers’ share of the margins to be netted against the RESA regulatory asset balance.

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 the RESA regulatory asset balance $22 million and $46 million in 2013 and 2012, respectively. The cumulative credit to the RESA regulatory asset balance was $104.5 million and $82.8 million at Dec. 31, 2013 and Dec. 31, 2012, respectively. The credits include the customers’ share of REC trading margins and the customers’ share of carbon offset funds.

This sharing mechanism will be effective through 2014. The CPUC is then expecting to review the framework and evidence regarding actual deliveries before determining to continue the sharing mechanism.

ECA / RESA Adjustment — In July 2013, PSCo advised the CPUC that it had inadvertently allocated purchased power expense between the deferred accounts for the ECA and the RESA from 2010 to 2012. PSCo proposed to transfer from the RESA deferred account to the ECA deferred account approximately $26.2 million and to amortize the recovery of this amount over 12 months. In addition, interest of $4.4 million was accrued on the amount related to the RESA. In January 2014, the ALJ determined that the $26.2 million was prudently incurred and recommended full recovery through the ECA over a 12 month period with interest accrued at the ECA interest rate. The difference between the RESA interest rate and the ECA interest rate is a decrease of approximately 7.4 percent, or $4.3 million.

Pending and Recently Concluded Regulatory Proceedings — FERC

Production Formula Rate ROE Complaint — In August 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates effective Sept. 1, 2013, which could reduce revenues approximately $2 million per year prospectively. The matter is currently pending the FERC’s action.

Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from a HTY formula rate to a forecast transmission formula rate and to establish formula ancillary services rates.  PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up.  The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million annually.  Various transmission customers taking service under the tariff protested the filing.  In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures.

In June 2012, several wholesale customers filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012.  If implemented, the ROE reduction would reduce PSCo transmission and ancillary rate revenues by approximately $1.8 million annually.  In October 2012, the FERC issued an order accepting the complaint, consolidating the complaint with the April 2012 formula rate change filing, establishing a refund effective date of July 1, 2012, and setting the complaint for settlement judge and hearing procedures.  

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In October 2013, PSCo and the wholesale customers filed a partial settlement that would resolve all issues related to the April 2012 transmission rate filing and June 2012 complaint other than ROE. The settlement is not expected to materially increase 2013 transmission revenues. In December 2013, the FERC approved the partial settlement. The ROE issue is now in an evidentiary hearing process. Initial testimony was filed in December 2013. PSCo filed testimony supporting the current ROE of 10.25 percent, while customers filed testimony recommending an ROE of 9.07 percent for the period July 2012 to November 2012, and an ROE of 8.92 percent thereafter. The case is scheduled for a hearing before an ALJ in May 2014, with the ALJ recommended decision by September 2014.

12. Commitments and Contingencies

Commitments

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

CACJA — The CACJA required PSCo to file a plan to reduce annual emissions of NOxby at least 70 to 80 percent or greater from 2008 levels by 2017 from its coal fired generation resources. In September 2012, the EPA formally approved the Colorado SIP for regional haze, including resource planning changes that include early coal-fueled plant retirements, fuel switching and SCR installation.

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 system renewal projects and increased maintenance.

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 2014 and 2060.  PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.

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The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2013, were as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2014	$	330.3	$	384.3	$	137.2
2015	265.4		228.0		136.5
2016	232.2		225.6		77.1
2017	153.8		222.1		50.9
2018	42.5		278.4		50.8
Thereafter	424.7		1,211.1		854.4
Total	$	1,448.9	$	2,549.5	$	1,306.9

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 2027 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 $72.7 million, $119.5 million and $178.8 million in 2013, 2012 and 2011, respectively.  At Dec. 31, 2013, the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)	Capacity		Energy (a)
2014	$	82.4	$	43.6
2015	82.6		36.8
2016	58.3		18.6
2017	35.2		3.1
2018	28.1		—
Thereafter	69.9		—
Total	$	356.5	$	102.1

^(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 (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 $144.2 million and $148.7 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2013 and 2012, respectively.

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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 $6.3 million, $5.7 million, and $3.2 million for 2013, 2012 and 2011, respectively.  Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Storage, leaseholds and rights	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital lease	221.2			221.2
Accumulated depreciation	(41.8		)	(35.5		)
Total property held under capital leases, net	$	179.4		$	185.7

The remainder of the leases, primarily for certain PPAs, office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment are accounted for as operating leases.  Total expenses under operating lease obligations were approximately $96.6 million, $77.9 million and $71.3 million for 2013, 2012 and 2011, respectively.  These expenses included capacity payments for PPAs accounted for as operating leases of $79.6 million, $59.4 million and $47.9 million in 2013, 2012 and 2011, respectively, recorded to electric fuel and purchased power expenses.

Included in the future commitments under operating leases are estimated future 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 Operating Leases(a) (b)		Total Operating Leases		Capital Leases
2014	$	14.8	$	94.8	$	109.6	$	30.6
2015	14.6		95.3		109.9		30.5
2016	11.7		84.0		95.7		29.3
2017	6.9		78.7		85.6		25.6
2018	6.6		79.3		85.9		25.2
Thereafter	48.0		548.6		596.6		538.2
Total minimum obligation							679.4
Interest component of obligation							(500.0		)
Present value of minimum obligation							$	179.4

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

^(b)  PPA operating leases contractually expire through 2028.

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

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

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

PSCo has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities.  PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  PSCo had approximately 1,441 MW and 1,433 MW of capacity under long-term PPAs as of Dec. 31, 2013, and 2012, respectively, with entities that have been determined to be variable interest entities.  These agreements have expiration dates through the year 2028.

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Environmental Contingencies

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

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

MGP Sites— PSCo is currently involved in investigating and/or remediating several MGP sites where hazardous or other regulated materials may have been deposited. PSCo has identified two sites, where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. PSCo anticipates that the majority of the remediation at these sites will continue through at least 2014. PSCo had accrued $1.2 million and $0.4 million for both these sites at Dec. 31, 2013 and 2012, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and waste

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

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. It is not yet known when the EPA will issue a finalized rule. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on PSCo is uncertain at this time.

Federal CWA Section 316 (b) — 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. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule is anticipated in April 2014. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements.

Proposed Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of hazardous waste. In 2010, the EPA published a proposed rule on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. PSCo’s costs for the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted if the EPA ultimately issues a rule under which coal ash is regulated as hazardous waste. The EPA has entered into a consent decree to act on final regulations by December 2014. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

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Air

EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. This finding required the EPA to adopt GHG emission standards for mobile sources. In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld on appeal to the D.C. Circuit. The U.S. Supreme Court has granted review on one issue related to these rules, specifically whether the EPA’s regulation of GHG emissions from mobile sources triggered, by operation of law, new source review permitting requirements for stationary sources, which was the EPA’s basis for adopting the 2011 permitting rules. The Court is scheduled to hear arguments in February 2014. A ruling is anticipated by June 2014. PSCo is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at PSCo’s power plants.

GHG Emission Standard for Existing Sources and NSPS Proposal — In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.

In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish CO₂ emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. PSCo expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. PSCo believes EGU MATS costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — In 2005, the EPA amended the BART requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze SIP, Colorado identified the PSCo facilities that will have to reduce SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a SIP that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Emission controls at the Hayden and Pawnee plants are projected to cost $359.5 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates.

The Colorado Mining Association (CMA) challenged the SIP in Colorado District Court. The District Court dismissed the CMA’s challenge in 2012, and the Colorado Court of Appeals upheld the District Court’s decision in November 2013. The CMA did not petition for review by the Colorado Supreme Court, thus ending the case.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10^th Circuit to review the EPA’s decision approving the SIP. WildEarth Guardians has stated it will challenge the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that SCR be added to the units. PSCo intervened in the case. The 10^th Circuit is scheduled to hear argument in November 2014, following completion of the briefs in August 2014.

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

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Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where PSCo operates power plants, current monitored air concentrations are below the level of the final annual primary standard. The EPA is expected to designate non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made.

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

Asset Retirement Obligations

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

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

A reconciliation of PSCo’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012, respectively:

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

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(Thousands of Dollars)	Beginning Balance Jan. 1, 2012		Liabilities Recognized		Liabilities Settled			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2012
Electric plant
Steam and other production asbestos	$	23,062	$	—	$	(9,372	)	$	1,536	$	4,508		$	19,734
Steam and other production ash containment	9,449		—		—			499		2,971			12,919
Wind production	—		2,928		—			—		—			2,928
Electric distribution	8,005		—		—			290		(1,903		)	6,392
Other	583		—		—			25		19			627
Natural gas plant
Gas transmission and distribution	810		—		—			48		(16		)	842
Common and other property
Common miscellaneous	298		—		—			11		—			309
Total liability	$	42,207	$	2,928	$	(9,372	)	$	2,409	$	5,579		$	43,751

In 2013, PSCo revised asbestos, ash containment facilities, radiation sources, miscellaneous electric production, electric transmission and distribution, natural gas transmission and distribution and common general AROs due to revised estimated cash flows. Additionally, in 2013, an ARO was recorded to reflect the expected costs with the retirement of certain gas gathering facilities and an ARO was settled for the asbestos abatement at the Cameo generating facility.

In 2012, PSCo revised asbestos, ash containment facilities and electric transmission and distribution AROs due revised estimated cash flows. Additionally, in 2012, an ARO was recorded to reflect the expected costs with the retirement of certain wind production facilities.

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

Removal Costs — PSCo records a regulatory liability for the plant removal costs of steam and other generation, transmission and distribution facilities.  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, 2013 and 2012 were $359 million and $365 million, respectively.

Legal Contingencies

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

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Employment, Tort and Commercial Litigation

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

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

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

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

A hearing in this case was held before a FERC ALJ and concluded in October 2013. The matter is presently being briefed, and the ALJ is expected to issue an initial decision on or before March 18, 2014.

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

Other Contingencies

See Note 11 for further discussion.

13. Regulatory Assets and Liabilities

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

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The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2013 and 2012 were:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	8	Various	$	45,504	$	447,752	$	38,219	$	613,391
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		116,477		—		100,060
Contract valuation adjustments (b)	10	Term of related contract	3,620		16,474		3,763		20,094
Depreciation differences	1	One to seventeen years	10,917		95,844		5,274		50,057
Net AROs (c)	1, 12	Plant lives	—		39,986		—		40,184
Conservation programs (d)	1, 11	One to five years	13,883		19,430		16,887		28,528
Gas pipeline inspection costs	12	One to four years	5,416		14,978		5,416		15,220
Renewable resources and environmental initiatives	12	One to two years	22,325		—		42,647		1,807
Purchased power contract costs	12	Term of related contract	—		30,069		—		28,164
Losses on reacquired debt	4	Term of related debt	1,572		9,804		1,964		11,376
Recoverable purchased natural gas and electric energy costs	1	Less than one year	18,022		—		15,007		—
Property tax		One to three years	18,427		30,626		6,005		12,010
Other		Various	10,477		4,597		8,507		13,837
Total regulatory assets			$	150,163	$	826,037	$	143,689	$	934,728

^(a)  Includes $4.1 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, 2013 and 2012, respectively.

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

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

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

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The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2013 and 2012 were:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	1, 12	Plant lives	$	—	$	359,387	$	—	$	365,331
Deferred electric, gas and steam production costs	1	Less than one year	33,247		—		22,022		—
Investment tax credit deferrals	1, 7	Various	—		24,038		—		25,790
Deferred income tax adjustment	1	Various	—		18,770		—		20,218
Conservation programs (a)	1, 11	Less than one year	12,188		—		2,522		—
Renewable resources and environmental initiatives	11, 12	Various	—		1,412		—		1,412
Low income discount program		Less than one year	4,084		—		4,205		—
Gain from asset sales		One to three years	1,687		368		2,414		2,039
PSCo earnings test	11	One to two years	22,892		19,203		1,732		1,732
Other		Various	5,401		1,512		828		882
Total regulatory liabilities			$	79,499	$	424,690	$	33,723	$	417,404

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

At Dec. 31, 2013 and 2012, approximately $136 million and $135 million of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with renewable resources and environmental initiatives.

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14. Other Comprehensive Income

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

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

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

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
Gains on cash flow hedges:
Interest rate derivatives	$	(730	)	(a)
Vehicle fuel derivatives	(40		)	(b)
Total, pre-tax	(770		)
Tax expense	294
Total amounts reclassified, net of tax	$	(476	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

15. Segments and Related Information

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

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

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

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

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2011
Operating revenues (a)	$	3,114,370	$	1,087,749	$	38,683		$	—		$	4,240,802
Intersegment revenues	318		242		—			(560		)	—
Total revenues	$	3,114,688	$	1,087,991	$	38,683		$	(560	)	$	4,240,802
Depreciation and amortization	$	265,078	$	59,189	$	4,315		$	—		$	328,582
Interest charges and financing costs	149,291		33,249		939			—			183,479
Income tax expense (benefit)	202,355		30,957		(4,951		)	—			228,361
Net income	334,516		55,446		6,841			—			396,803

^(a)  Operating revenues include $12.6 million, $13.7 million and $15.3 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 16 for further discussion of related party transactions by reportable segment.

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16. Related Party Transactions

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

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

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

(Thousands of Dollars)	2013		2012		2011
Operating revenues:
Electric	$	8,136	$	9,271	$	10,896
Other	4,441		4,441		4,441
Operating expenses:
Purchased power	1,331		6,539		7,187
Other operating expenses — paid to Xcel Energy Services Inc.	375,766		316,548		338,889
Interest expense	132		114		112
Interest income	273		122		59

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

	2013				2012
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	18,065	$	—	$	23,214	$	—
NSP-Wisconsin	8		—		71		—
SPS	1,056		—		69		—
Other subsidiaries of Xcel Energy Inc.	7		45,902		70,190		30,001
	$	19,136	$	45,902	$	93,544	$	30,001

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17. Summarized Quarterly Financial Data (Unaudited)

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

	Quarter Ended
(Thousands of Dollars)	March 31, 2012		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012
Operating revenues	$	1,076,052	$	869,501	$	992,287	$	1,031,453
Operating income	188,906		192,310		315,391		152,612
Net income	93,285		95,407		192,443		76,941

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, 2013, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting.  PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting.  PSCo has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.  During the year and in preparation for issuing its report for the year ended Dec. 31, 2013 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.

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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

Item 14 — Principal Accountant Fees and Services

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2014 Annual Meeting of Shareholders, which is incorporated by reference.

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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, 2013.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2013, 2012, and 2011.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2013, 2012, and 2011.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2013, 2012, and 2011.
	Consolidated Balance Sheets — As of Dec. 31, 2013 and 2012.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Consolidated Statements of Capitalization — As of Dec. 31, 2013 and 2012.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2013, 2012, and 2011.
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:

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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)
May 1, 1996	10-Q, June 30, 1996	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
Sept. 1, 2002	8-K, Sept. 18, 2002(001-03280)	4.01
Sept. 15, 2002	10-Q, Sept. 30, 2002(001-03280)	4.04
March 1, 2003	S-3, April 14, 2003 (333-104504)	4(b)(3)
April 1, 2003	10-Q May 15, 2003 (001-03280)	4.02
May 1, 2003	S-4, June 11, 2003 (333-106011)	4.9
Sept. 1, 2003	8-K, Sept. 2, 2003 (001-03280)	4.02
Sept. 15, 2003	Xcel 10-K, March 15, 2004 (001-03034)	4.100
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 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. 14, 2007).
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. 16, 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 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 dated March 26, 2013 (file no. 001-03280)).
10.01*+	Xcel Energy Non-Qualified 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 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 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).

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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 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 10I(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 10I(2)).
10.08*	Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (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 (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 Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.13*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
10.14*+	Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.15*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.16*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.17*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.18a*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.18b*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Time-Based Restricted Stock Unit Agreement (Exhibit 10.14b to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2012).
10.19*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed Apr. 5, 2011).
10.20*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (as amended and restated effective Nov. 29, 2011) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.21*+	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).
10.22*	Amended and Restated Credit Agreement, dated as of July 27, 2012 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.03 to Xcel Energy Inc.’s Form 8-K, dated July 27, 2012 (file no. 001-03034)).
10.23*+	First Amendment dated Feb. 20, 2013 to the Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.24*+	Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.25*+	First Amendment dated May 21, 2013 to the Xcel Energy Inc. Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.26*+	Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Non-Qualified 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).

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10.27*+ Xcel Energy 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).

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, 2013 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, 2013, 2012 AND 2011

(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:
2013	$	21,918	$	16,784	$	7,005	$	23,202	$	22,505
2012	24,698		16,323		7,648		26,751		21,918
2011	24,054		20,371		7,423		27,150		24,698

^(a)  Recovery of amounts previously written off.

^(b)  Principally bad debts written off.

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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, 2014	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Senior 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/ DAVID L. EVES	/s/ BENJAMIN G.S. FOWKE III
David L. Eves	Benjamin G.S. Fowke III
President, Chief Executive Officer and Director	Chairman and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN	/s/ JEFFREY S. SAVAGE
Teresa S. Madden	Jeffrey S. Savage
Senior Vice President, Chief Financial Officer and Director	Vice President and Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ DAVID M. SPARBY
David M. Sparby
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.

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