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, 2011

Or

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

Commission file number 001-03280

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 o 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 o 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.

o Large accelerated filer	oAccelerated filer
x Non-accelerated filer	o Smaller Reporting Company
(Do not check if a smaller reporting company)

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

As of Feb. 27, 2012, 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 2012 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).

INDEX

PART I	3
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	6
Public Utility Regulation	6
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	8
Fuel Sources	8
Renewable Energy Sources	9
Wholesale Commodity Marketing Operations	10
Summary of Recent Regulatory Developments	10
Electric Operating Statistics	12
NATURAL GAS UTILITY OPERATIONS	13
Overview	13
Public Utility Regulation	13
Capability and Demand	14
Natural Gas Supply and Costs	14
Natural Gas Operating Statistics	15
ENVIRONMENTAL MATTERS	15
EMPLOYEES	16
Item 1A — Risk Factors	16
Item 1B — Unresolved Staff Comments	23
Item 2 — Properties	24
Item 3 — Legal Proceedings	25
Item 4 — Mine Safety Disclosures	25
PART II	25
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6 — Selected Financial Data	25
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	29
Item 8 — Financial Statements and Supplementary Data	30
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	74
Item 9A — Controls and Procedures	74
Item 9B — Other Information	75
PART III	75
Item 10 — Directors, Executive Officers and Corporate Governance	75
Item 11 — Executive Compensation	75
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	75
Item 13 — Certain Relationships and Related Transactions, and Director Independence	75
Item 14 — Principal Accountant Fees and Services	75
PART IV	75
Item 15 — Exhibits, Financial Statement Schedules	75
SIGNATURES	79

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

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NCE	New Century Energies, Inc.
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
PSRI	P.S.R. Investments, Inc.
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WYCO	WYCO Development LLC
Xcel Energy	Xcel Energy Inc. and subsidiaries
Federal and State Regulatory Agencies
CPUC	Colorado Public Utilities Commission
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
OCC	Colorado Office of Consumer Counsel
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
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
CIPS	Critical Infrastructure Protection Standards
CO2	Carbon dioxide
Codification	FASB Accounting Standards Codification
COLI	Corporate owned life insurance
CPCN	Certificate of public convenience and necessity
CWIP	Construction work in progress

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ERRP	Early retiree reimbursement program
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
IFRS	International Financial Reporting Standards
JOA	Joint operating agreement
MACT	Maximum achievable control technology
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator
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
O&M	Operating and maintenance
OCI	Other comprehensive income
PBRP	Performance-based regulatory plan
PCB	Polychlorinated biphenyl
PJM	PJM Interconnection, LLC
PPA	Purchased power agreement
Provident	Provident Life & Accident Insurance Company
PRP	Potentially responsible party
PV	Photovoltaic
REC	Renewable energy credit
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
WECC	Western Electricity Coordinating Council
Measurements
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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COMPANY OVERVIEW

PSCo was incorporated in 1924 under the laws of Colorado.  PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado.  The wholesale customers served by PSCo comprised approximately 19 percent of its total KWh sold in 2011.  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 2011.  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 customers in the following industries: fabricated metal products, as well as electric and gas services.  For small commercial and industrial customers, significant electric retail sales include customers in 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.  Following settlement with the IRS during 2007, such policies were terminated.  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 14 to the consolidated financial statements for further discussion relating to comparative segment revenues, net income and related financial information.

PSCo corporate strategy focuses on three core objectives: obtain stakeholder alignment; invest in our regulated utility businesses; and earn a fair return on our utility investments.  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 priority for PSCo and is designed to meet customer and policy maker expectations while creating shareholder value.

Seasonality

The demand for electric power generation 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.  Seasonal rates were implemented in June 2010 and are designed to be revenue neutral on an annual basis.  Although the quarterly pattern of revenue collection is different than in the past, as seasonal rates are higher in the summer months and lower throughout the other months of the year, 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 — Management’s Discussion of Financial Condition and Results of Operations.

Competition

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.  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.  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, such as municipalization.  While facing these challenges, PSCo’s rates are competitive with currently available alternatives.

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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 NERC electric reliability standards and natural gas transactions in interstate commerce.  See Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules for further discussion.

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.  Effective January 2011, the PCCA began to recover the revenue requirement associated with the purchase of the Blue Spruce Energy Center and Rocky Mountain Energy Center. Recovery of the revenue requirement for these facilities will be moved from the PCCA to base rates in mid 2012, as part of the PSCo electric rate case.

· 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.  Beginning 2010, the CPUC approved recovery of the full amount of DSM-related costs through the combination of base rates and a DSMCA tracker mechanism.

· RESA — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of 2 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.

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 renewable energy purchase and generation costs through a fuel clause and in exchange receive renewable energy credits associated with those resources.

PBRP and QSP Requirements — PSCo currently operates under an electric PBRP.  This regulatory plan includes 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 through 2012.  PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP.  In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP.  The CPUC conducts proceedings to review and approve these rate adjustments annually.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2012, assuming normal weather, is listed below.

System Peak Demand (in MW)
2009		2010	2011	2012 Forecast
	6,311	6,436	6,896	6,313

The peak demand for PSCo’s system typically occurs in the summer.  The 2011 uninterrupted system peak demand for PSCo occurred on July 18, 2011 and was higher than 2010 and the 2012 forecasted peak demand primarily due to backup load to serve the non-PSCo joint owners of Comanche Unit 3, which was offline when the peak demand occurred.

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.

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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.

PSCo Resource Plan — In October 2011, PSCo filed the 2011 electric resource plan.  Beginning in 2017, PSCo is projected to have relatively low resource needs and has proposed to fill these needs with a competitive resource acquisition process.  The CPUC will consider the resource plan in two phases.  In the first phase, the CPUC will review planning assumptions, competitive bidding structure, and determine if PSCo should acquire generation technology.  The first phase is expected to be completed by the end of 2012.  In the second phase, PSCo will conduct the competitive acquisition process, which is expected to be submitted to the CPUC for approval in 2013.

RES Compliance Plan — Colorado has a law that mandates that at least 30 percent of PSCo’s energy sales be supplied by renewable energy by 2020 and includes a distributed generation standard.  PSCo has filed the 2012 and 2013 RES compliance plan.  PSCo proposed to acquire up to 30 MW of customer-sited solar projects each year and up to 6 MW of community scale solar projects.  A decision on the 2012 and 2013 plan is expected in the first quarter of 2012.  PSCo currently recovers any incentives paid through a combination of the ECA and RESA cost-recovery mechanisms.

Solar*Rewards Program — In March 2011, the CPUC approved a settlement that limits the amount of customer sited solar generation that PSCo will purchase, caps the amount PSCo will spend on customer sited solar generation and shifts from up-front payments to pay-for-performance.  The settlement gives PSCo a presumption of prudence, for both the existing RESA balance, and the future RESA balance if PSCo performs consistent with the acquisition terms of the settlement.

Separately, the CPUC approved a change to the treatment of REC trading margins that allows the customers’ share of the margins through the end of the pilot period, approximately $54 million, to be netted against the RESA regulatory asset balance.  During the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

CACJA — The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from the coal-fired generation identified in the plan.  The plan allows PSCo to propose emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by 2017.  The total investment associated with the adopted plan is approximately $1.0 billion through 2017 and the rate impact is expected to increase future bills on average by 2 percent annually.

In December 2010, the CPUC approved the following:

· Shutdown Cherokee Units 2 and 1 in 2011 and 2012, respectively, and Cherokee Unit 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);

· Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017;

· Shutdown Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (111 MW) in 2014 to natural gas;

· Shutdown Valmont Unit 5 (186 MW) in 2017;

· Install SCR for controlling NOx and a scrubber for controlling SO2 on Pawnee Generating Station in 2014;

· Install SCRs on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and

· Convert Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.

PSCo has received CPCNs for the conversion of Cherokee Unit 2 to a synchronous condenser, for the decommissioning of Cherokee Unit 1 and Unit 2, and for the Pawnee emissions controls.  In addition, PSCo has filed for CPCNs for the new natural gas combined-cycle at Cherokee station and the Hayden emissions controls.

San Luis Valley-Calumet-Comanche Transmission Project — In May 2009, PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a 230 KV and 345 KV line and substation construction project.  The line was intended to assist in bringing solar power in the San Luis Valley to customers.  The line was originally expected to be placed in-service in 2013; however, due to delays in the siting and permitting of the line, the in-service date was delayed.

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In October 2011, in conjunction with the filing of the electric resource plan, PSCo determined that due to lower projected load growth, lower gas prices and the higher cost of solar thermal generation, it was unlikely to need the transmission line in the foreseeable future.  A CPUC decision on the resource plan is expected in late 2012.

SmartGridCity™ CPCN — As part of the PSCo 2010 electric rate case, the CPUC included recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred by PSCo to develop and operate SmartGridCity™, subject to refund, and ordered PSCo to file for a CPCN for that project.

In February 2011, the CPUC approved the CPCN and allowed recovery of approximately $28 million of the capital cost and 100 percent of the O&M costs and ordered PSCo to file for a rate reduction in April 2011 to reflect the lower level of capital in rate base.  On July 1, 2011, PSCo implemented an annual rate reduction of $2.8 million.  In December 2011, PSCo filed an application addressing the additional information requested.  A decision is expected in the third quarter of 2012.

Boulder, Colo. Franchise Agreement — 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 (and extended the tax until the earlier to occur of (1) Dec. 31, 2017, (2) when Boulder decides not to create a municipal utility, or (3) when Boulder commences delivery of municipal electric utility services) for the purpose of 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, but not limited to, the level of initial rates and debt service coverage.  Boulder has retained legal counsel specializing in condemnation and plans to retain legal counsel specializing in FERC matters.  The City Council has not yet decided whether it will proceed with the formation of a municipal electric utility or with commencing a condemnation proceeding.  Should Boulder proceed with these actions and be successful, PSCo would seek to obtain full compensation for the property and business taken by Boulder and for all damages resulting to PSCo and its system. PSCo would also seek appropriate compensation for stranded costs with the FERC.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for 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
	Cost			Percent			Cost			Percent			Fuel Cost
2011		$	1.77		76	%		$	4.98		24	%		$	2.54
2010			1.58		85				5.05		15				2.11
2009			1.52		82				3.99		18				1.97

See Item 1A 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, 2011 and 2010 were approximately 48 and 34 days usage, respectively.  PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming.  During 2011 and 2010, PSCo’s coal requirements for existing plants were approximately 10.5 and 10.7 million tons, respectively.  The estimated coal requirements for 2012 are approximately 11.6 million tons.

PSCo has contracted for coal supply to provide 100 percent of its coal requirements in 2012, 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 2012 and 2013.  Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather, and availability of equipment.

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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, 2010, PSCo’s commitments related to gas supply contracts were approximately $817 million and commitments related to gas transportation and storage contracts were approximately $838 million.  At Dec. 31, 2011, PSCo’s commitments related to gas supply contracts, which expire in various years from 2012 through 2021, were approximately $730 million and commitments related to gas transportation and storage contracts, which expire in various years from 2012 through 2060, were approximately $819 million.

Renewable Energy Sources

PSCo’s renewable energy portfolio includes wind, biomass, solar, and hydroelectric power from both owned generating facilities and purchased power agreements.Renewable energy comprised 14.6 percent and 11.7 percent of PSCo’s total owned and purchased energy for 2011 and 2010, respectively.  Biomass, solar and hydroelectric power comprised approximately 2.2 percent and 1.4 percent of renewable energy for 2011 and 2010, respectively, with the remaining renewable energy provided by wind.  As of Dec. 31, 2011, PSCo is in compliance with its renewable portfolio standards, which require generation from renewable resources of 12 percent of electric retail sales.

PSCo acquires the majority of its wind energy from purchased power agreements with wind farm owners, primarily in Colorado and Wyoming.  PSCo currently has 18 of these agreements in place, with facilities ranging in size from under 3 MW to 300 MW.  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 for each of 2011 and 2010.  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 2011 have benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to expiration of the Federal Production Tax Credits in 2012.

In 2011, the new 252 MW Cedar Point Wind Project and the 251 MW Cedar Creek II Wind Farm began commercial operations.  PSCo has long-term purchased power agreements to acquire the output of both facilities.  PSCo has agreed to purchase 200 MW of wind power from NextEra Energy Resources’ Limon Wind Energy Center and an additional 200 MW from NextEra Energy Resources’ Limon Wind Energy Center II, which are both expected to be completed in 2012.  The average cost over the 25 year term of  these contracts is approximately $35 per MWh, which is lower than the average cost per MWh of purchased wind energy on the PSCo system.  By the end of 2012, PSCo plans to have approximately 2,200 MW of wind on its system.

Additionally, PSCo owns and operates the 26.4 MW Ponnequin Wind Farm in northern Colorado, which has been in service since 1998.  PSCo collectively had nearly 1,800 MW and 1,300 MW of wind energy on its system at the end of 2011 and 2010, respectively.  Wind energy comprised 12.4 percent and 10.3 percent of PSCo’s total owned and purchased energy for 2011 and 2010, respectively.

PSCo also offers customer-focused renewable energy initiatives.  The Windsource® program allows customers to purchase a portion or all of their electricity from renewable sources.  Approximately 35,843 and 38,762 customers in Colorado purchased 211,511 MWh and 212,900 MWh of electricity under the Windsource program in 2011 and 2010, respectively.  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 9,600 PV systems with approximately 110 MW of aggregate capacity and over 7,100 PV systems with approximately 76 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2011 and Dec. 31, 2010, respectively.

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

FERC Transmission Planning and Cost Allocation —In July 2011, the FERC issued Order 1000 adopting modified rules for regional transmission planning, wholesale transmission cost allocation and transmission development.  The new rules would eliminate any preferential right at the federal level for an incumbent transmission provider to construct transmission facilities subject to regional cost allocation, referred to as a ROFR.  The transmission planning processes will be subject to additional tariff revisions subsequent to Order 1000 compliance filings due in October 2012.

Order 1000 will require significant changes in transmission planning and cost allocation mechanisms in the WestConnect region where PSCo is located.  PSCo and WestConnect are in the process of determining the impacts of the new Order 1000 requirements related to future transmission development and ownership.  Irrespective of the new rules, PSCo is pursuing new transmission facility projects.

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 U.S. Court of Appeals for the Ninth Circuit.

In an order issued in August 2007, the U.S. Court of Appeals remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets.  The U.S. Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued.  The FERC has issued an order on establishing principles for the review proceeding and encouraging a settlement.  The settlement process is in progress.

FERC Penalty Guidelines — The Energy Act required the FERC to adopt new regulations to implement various aspects of the Energy Act.  Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

In September 2010, the FERC issued a policy statement establishing guidelines to determine the financial penalties that would be applied for violations of FERC statutes, rules and orders, including violations of NERC mandatory reliability standard violations investigated by the FERC.  The guidelines established a base violation level for various types of violations, plus mitigating or aggravating factor adders and multipliers, depending on the nature and severity of the violation.  Base penalties range between a minimal amount and $72.5 million based on an application of a multiplier.  The guidelines indicate that the FERC can deviate from the guidelines in its discretion.  The guidelines can apply to any investigation where the FERC Staff has not begun settlement negotiations regarding an alleged violation.

While PSCo cannot predict the ultimate impact new FERC regulations will have on its results of operations, cash flows or financial position, PSCo continues to take action to comply with existing rules and to implement new FERC rules and regulations as they become effective.

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FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement commenced a non-public investigation of the transmission service arrangements across the Lamar Tie Line, a transmission facility that connects PSCo and SPS.  In July 2008, the FERC issued a preliminary report alleging Xcel Energy violated certain FERC policies, rules and approved tariffs that could result in material penalties under the FERC penalty guidelines.  The report did not constitute a finding by the FERC.  Xcel Energy disagreed with the preliminary report and demonstrated compliance with applicable standards.  In November 2011, Xcel Energy and SPP filed proposed tariff revisions clarifying the transmission arrangements across the Lamar Tie Line prospectively.

In January 2012, the FERC approved a stipulation and consent agreement in which PSCo did not admit any violations but agreed to pay a $1 million civil penalty.  The FERC contemporaneously issued an order approving changes to the Xcel Energy OATT to allow continued network service arrangements under the tariff.

Electric Transmission Rate Regulation — The FERC regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control of their electric transmission assets for the sale of electric transmission services to an RTO.  Each RTO separately files regional transmission tariff rates for approval by the FERC.  All members within that RTO are then subjected to those rates.  In 2009, PSCo filed a tariff to participate with other utilities in WestConnect, a consortium of utilities offering regionalized non-firm transmission services.  The WestConnect tariff was effective in the first quarter of 2009 and the FERC approved a two year extension in the second quarter of 2011.  The WestConnect tariff has not had a material impact on PSCo transmission usage or revenues.  WestConnect may provide wholesale energy market functions in the future, but would not be an RTO.

Market-Based Rate Rules — PSCo was granted market-based rate authority.  PSCo was reauthorized to sell at market-based rates outside its service territory in 2011.  Presently, Xcel Energy Inc.’s utility subsidiaries may not sell power at market-based rates within the PSCo balancing authorities, where they have been found to have market power under the FERC’s applicable analysis. PSCo has cost-based coordination tariffs that they may use to make sales in their balancing authorities.

NERC Compliance Audits and Self-Reports — In 2010 and 2011, PSCo a filed self-report with the WECC regarding potential violations of certain NERC CIPS.  Based on the issues identified with CIPS compliance, the utility subsidiaries submitted a mitigation plan that provides for a comprehensive review of the utility subsidiaries’ CIPS compliance programs.  Following this comprehensive review, additional self-reports of potential violations were filed.

In May 2011, PSCo was subject to a comprehensive triennial audit by the WECC regarding compliance with various NERC mandatory reliability standards.  In December 2011, PSCo and WECC agreed to a settlement in principle of five violations of four NERC reliability standards, including the two violations self-reported prior to the May 2011 audit.  The violations were all self-identified and self-reported to WECC.  PSCo agreed to pay an immaterial penalty to resolve all five reliability standard violations.  Following execution of the settlement agreement, the agreement must be approved by NERC’s Board of Trustees and filed with FERC for further approval.

NERC Advisory Regarding Impact of Transmission Field Conditions on Facility Ratings — In 2010, the NERC issued an advisory requiring utilities to perform an assessment of field versus assumed “as built” transmission infrastructure conditions and allowed for affected entities to complete their initial assessment and corrective actions by 2013 and 2014, respectively.  The advisory compliance cost for PSCo is estimated at $6.8 million.  PSCo will seek recovery through applicable rate-making mechanisms.

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Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2011			2010			2009
Electric sales (Millions of KWh)
Residential		9,149			9,087			8,715
Large commercial and industrial		6,445			6,328			6,147
Small commercial and industrial		12,663			12,656			12,301
Public authorities and other		226			227			226
Total retail		28,483			28,298			27,389
Sales for resale		6,595			7,079			6,949
Total energy sold		35,078			35,377			34,338
Number of customers at end of period
Residential		1,166,567			1,159,287			1,150,181
Large commercial and industrial		325			322			322
Small commercial and industrial		153,111			152,349			151,315
Public authorities and other		55,547			56,837			58,371
Total retail		1,375,550			1,368,795			1,360,189
Wholesale		24			26			30
Total customers		1,375,574			1,368,821			1,360,219
Electric revenues (Thousands of Dollars)
Residential	$	1,024,051		$	1,013,188		$	862,242
Large commercial and industrial		421,410			404,544			346,951
Small commercial and industrial		1,180,985			1,147,572			962,819
Public authorities and other		46,985			48,847			44,434
Total retail		2,673,431			2,614,151			2,216,446
Wholesale		347,672			368,396			349,909
Other electric revenues		93,267			72,498			112,223
Total electric revenues	$	3,114,370		$	3,055,045		$	2,678,578
KWh sales per retail customer		20,706			20,674			20,136
Revenue per retail customer	$	1,944		$	1,910		$	1,630
Residential revenue per KWh		11.19	¢		11.15	¢		9.89	¢
Large commercial and industrial revenue per KWh		6.54			6.39			5.64
Small commercial and industrial revenue per KWh		9.33			9.07			7.83
Wholesale revenue per KWh		5.27			5.20			5.04

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Energy Source Statistics

	Year Ended Dec. 31
	2011					2010					2009
	Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation
Coal		22,065		61	%		22,767		61	%		19,423		53	%
Natural Gas		8,896		24			9,854		27			12,687		35
Wind (a)		4,518		12			3,830		10			3,563		10
Hydroelectric		681		2			446		1			730		2
Other (b)		324		1			257		1			118		-
Total		36,484		100	%		37,154		100	%		36,521		100	%
Owned generation		23,743		65	%		24,444		66	%		18,848		52	%
Purchased generation		12,741		35			12,710		34			17,673		48
Total		36,484		100	%		37,154		100	%		36,521		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 nuclear, solar, biomass, oil and waste.  Distributed generation from the Solar*Rewards program is not included.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of PSCo are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and commercial and industrial (C&I) customer, as a result of improved building construction technologies, higher appliance efficiencies, and conservation.  From 2000 to 2011, average annual sales to the typical PSCo residential customer declined from 92 MMBtu per year to 78 MMBtu per year, and to the typical C&I customer declined from 455 MMBtu per year to 377 MMBtu per year 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.

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 also subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce.  PSCo is subject to the DOT and the CPUC with regards to pipeline safety compliance.

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

· GCA — The GCA recovers the actual costs of purchased gas and transportation to meet the requirements of its customers and is revised quarterly to allow for changes in gas rates.  Effective September 2011, the GCA recovers the return on gas in underground storage.

· DSMCA — PSCo has 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.

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QSP Requirements — The CPUC established a natural gas QSP.  This regulatory plan includes 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 through 2012.  The CPUC conducts proceedings to review and approve the rate adjustment annually.

See Note 11 to the consolidated financial statements for further discussion.

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law on Jan. 3, 2012 (“Pipeline Safety Act”) requires, among other things, 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. Where records are inadequate to confirm the maximum allowable operating pressure, the DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure, a process that could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and/or, if appropriate, develop new regulations, addressing a variety of subjects, including: requiring use of automatic or remote-controlled shut-off valves in certain circumstances; requiring testing of previously untested transmission lines located within high consequence areas operating at a pressure greater than 30 percent of specified minimum yield stress; and expanding integrity management requirements beyond high consequence areas. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $0.2 million per violation per day up to $2 million for a related series of violations.  While PSCo cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, PSCo is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be 1,926,635 MMBtu.  In addition, firm transportation customers hold 565,008 MMBtu of capacity for PSCo without supply backup.  Total firm delivery obligation for PSCo is 2,491,643 MMBtu per day.  The maximum daily deliveries for PSCo for firm and interruptible services were 2,155,547 MMBtu on Feb. 1, 2011 and 1,820,806 on Jan. 7, 2010.

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 1,847,668 MMBtu per day, which includes 853,453 MMBtu of natural gas held under third-party underground storage agreements.  In addition, PSCo operates three company-owned underground storage facilities, which provide about 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 and a small amount is received directly from wellhead sources.

PSCo is required by CPUC regulations to file a natural gas purchase plan by June of 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.  This diversification involves numerous supply sources with varied contract lengths.

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:

2011	$	4.99
2010		5.10
2009		5.13

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, 2011, PSCo was committed to approximately $1.1 billion in such obligations under these contracts, which expire in various years from 2012 through 2029.

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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 2011, PSCo purchased natural gas from approximately 41 suppliers.

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

Natural Gas Operating Statistics

	Year Ended Dec. 31
	2011		2010		2009
Natural gas deliveries (Thousands of MMBtu)
Residential		94,947		95,231		95,566
Commercial and industrial		38,433		39,399		39,878
Total retail		133,380		134,630		135,444
Transportation and other		102,874		101,597		109,906
Total deliveries		236,254		236,227		245,350
Number of customers at end of period
Residential		1,209,210		1,200,950		1,193,418
Commercial and industrial		100,329		99,866		99,654
Total retail		1,309,539		1,300,816		1,293,072
Transportation and other		5,356		5,240		4,789
Total customers		1,314,895		1,306,056		1,297,861
Natural gas revenues (Thousands of Dollars)
Residential	$	746,133	$	736,160	$	745,728
Commercial and industrial		277,962		274,288		285,199
Total retail		1,024,095		1,010,448		1,030,927
Transportation and other		63,654		64,998		63,032
Total natural gas revenues	$	1,087,749	$	1,075,446	$	1,093,959
MMBtu sales per retail customer		101.85		103.50		104.75
Revenue per retail customer	$	782	$	777	$	797
Residential revenue per MMBtu		7.86		7.73		7.80
Commercial and industrial revenue per MMBtu		7.23		6.96		7.15
Transportation and other revenue per MMBtu		0.62		0.64		0.57

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 be granted the authority to recover the cost of these initiatives through rates.

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EMPLOYEES

As of Dec. 31, 2011, PSCo had 2,791 full-time employees, 2,122 of which are covered under collective bargaining agreements.  See Note 8 to the consolidated financial statements for further discussion.

Item 1A — Risk Factors

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 Xcel Energy Inc.’s Board of Directors oversees and holds management accountable.  As described more fully below, PSCo is faced with a number of different types of risk.  We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2; risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for our products and services.  Cross-cutting risks such as these 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 securities 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, which further mitigates risk.  Building on this culture of compliance, we manage and 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 also communicates with Xcel Energy Inc.’s Board and key stakeholders regarding risk.  Management provides information to Xcel Energy Inc.’s Board in presentations and communications over the course of the year.  Senior management presents an assessment of key risks to the Board annually.  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.  Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy Inc.’s and PSCo’s strategy.  The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees.  The standing committees also oversee risk management as part of their charters.  Each committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk.  Xcel Energy Inc.’s Board has overall responsibility for risk oversight.  As described above, the Board reviews the key risk assessment process presented by senior management.  This key risk assessment analyzes the most likely areas of future risk to Xcel Energy.  Xcel Energy Inc.’s Board also reviews the performance and annual goals of each business area.  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 registrations, 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, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination.  Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination.  At Dec. 31, 2011, 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, particulates and coal ash.  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.

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.

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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 currently 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, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred 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, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have a material 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 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.

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, such as the recent concerns regarding European sovereign debt.  Capital market disruption events and resulting broad financial market distress, such as the events surrounding the collapse in the U.S. sub-prime mortgage market, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

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

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We are subject to credit risks.

Credit risk includes the risk that our 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 Act may require broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity. Also, in October 2010, the FERC finalized its Order 741 rulemaking addressing the credit policies of organized electric markets, such as MISO.  FERC Order 741 limits the amount of overall credit available to entities operating within organized markets and places restrictions on netting of transactions within organized markets unless certain market protocols are implemented by the RTO.  Various RTOs are in the process of filing their proposed market protocols to satisfy FERC Order 741 and these new market designs may lead to additional margin requirements that could impact our liquidity.

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 PJM and MISO, in which any credit losses are socialized to all market participants.

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

Increasing costs associated with our defined benefit retirement plans and other employee benefits may adversely affect 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 beginning in 2008.  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.

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Operational Risks

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and 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 to our retail, wholesale and other customers at previously authorized or anticipated costs.  Any such disruption, if significant, could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costs relative to corresponding sales commitments 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, etc.

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

On a periodic basis, or as needed, our utility operations file long-term resource plans with our regulators.  These plans are based on numerous assumptions over the relevant planning horizon such as:  sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production, customer 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 could lead to under recovery of costs or insufficient resources to meet customer demand.

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

There are inherent in our natural gas transmission and distribution activities a variety of 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, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of potential damages resulting from these risks is greater.

Additionally, the cost of potential regulations related to pipeline safety could be significant.

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, 2011, Xcel Energy Inc. and its utility subsidiaries had approximately $8.8 billion of long-term debt and $1.3 billion of short-term debt and current maturities.  Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

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Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2011, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $67.5 million and $18 million of exposure.  Xcel Energy also had additional guarantees of $31.2 million at Dec. 31, 2011 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time.  If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

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

We have historically paid quarterly dividends to Xcel Energy Inc.  In 2011, 2010 and 2009 we paid $270.1 million, $265.8 million and $266.2 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay is limited to some extent by our indenture for our first mortgage bonds.

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.  In 2009, the U.S. submitted a non-binding GHG emission reduction target of 17 percent compared to 2005 levels pursuant to the Copenhagen Accord and negotiations continue under 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 are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA.  In December 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere.  This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles.  In January 2011, new EPA permitting requirements became effective 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 also announced that it will propose GHG regulations applicable to emissions from existing power plants, although the EPA announced in late September 2011 that this proposed rule will be delayed.

We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 12 to the consolidated financial statements.  An adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time 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 will be enacted.  The impact of legislation and regulations, on us and our customers 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.

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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, but are not limited to, rules associated with emission 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 the FERC’s 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, electric reliability standards that were historically subject to voluntary compliance 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.

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 may result in a sustained lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets.  A sustained lower level of economic activity may also result in a decline in energy consumption, which may adversely affect our revenues and future growth.  Instability in the financial markets, as a result of recession or otherwise, 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.

Current economic conditions may be exacerbated 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 significant decrease in revenues and significant additional costs to repair and insure our assets, which 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.  While we have already incurred increased costs for security and capital expenditures in response to these risks, 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 covering risks we and our competitors typically insure against may decrease.  In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. For example, wildfire events, particularly in the geographic areas we serve, may cause insurance for wildfire losses to become difficult or expensive to obtain.

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 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.

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The degree to which we are able to maintain day-to-day operations in response to unforeseen events, potentially through the execution of our business continuity plans, will in part determine the financial impact of certain events on our financial condition and results.It’s difficult to predict the magnitude of such events and associated impacts.

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

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets could be directly or indirectly affected by unintentional or deliberate cyber incidents.  Cyber intrusion or other similar events could harm our businesses by limiting our generating, transmitting and distributing capabilities or delay our development and construction of new facilities or capital improvement projects to existing facilities.  In addition, as generation and transmission systems as well as natural gas pipelines are part of an interconnected system, a disruption caused by the impact of a cyber security event of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources could also negatively impact our business. We are unable to quantify the potential impact of such cyber security threats. These events and corresponding regulatory action, if any, could result in a material decrease in revenues and may causesignificant additional costs (e.g., repairs/insurance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  Despite our control environment and security measures, our technology systems may be vulnerable to disability, failures or unauthorized access due to cyber intrusion.  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.  In addition, confidential and other data, including sensitive customer or employee information, could be compromised exposing us to liability and business disruption.

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

Electric Utility Generating Stations:

PSCo				Summer 2011
				Net Dependable
Station, Location and Unit	Fuel	Installed		Capability (MW)
Steam:
Arapahoe-Denver, Colo., 2 Units	Coal		1951-1955		153
Cherokee-Denver, Colo., 3 Units	Coal		1957-1968		611	(a)
Comanche-Pueblo, Colo.
Unit 1	Coal		1973		325
Unit 2	Coal		1975		335
Unit 3	Coal		2010		511	(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		65
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			173
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			5,256

(a) Cherokee Unit 2 was taken out of service in October 2011.

(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 generation values noted above.  The on-demand net maximum capacity is based on a company assumption of a 12.5 percent dependable generation rate.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2011:

Conductor Miles
345 KV	1,614
230 KV	12,177
138 KV	92
115 KV	4,931
Less than 115 KV	73,392

PSCo had 224 electric utility transmission and distribution substations at Dec. 31, 2011.

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Natural gas utility mains at Dec. 31, 2011:

Miles
Transmission	2,310
Distribution	21,414

Item 3 — Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against PSCo.  PSCo has recorded an estimate of the probable cost of settlement or other disposition for such matters.

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 had dividend restrictions imposed by FERC rules.

· 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.

The dividends declared during 2011 and 2010 were as follows:

(Thousands of Dollars)	2011		2010
First quarter	$	68,219	$	66,655
Second quarter		67,589		66,729
Third quarter		67,511		66,600
Fourth quarter		66,926		66,828

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 and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Financial Review

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

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of 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 $397 million for 2011, compared with approximately $400 million for 2010.  Earnings decreased due to the implementation of seasonal rates in June 2010 (seasonal rates are higher in the summer months and lower throughout the other months of the year), higher O&M expenses, depreciation expense and property taxes, partially offset by the favorable impact of warmer temperatures in the summer of 2011.

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)	2011			2010
Electric revenues	$	3,114		$	3,055
Electric fuel and purchased power		(1,425	)		(1,513	)
Electric margin	$	1,689		$	1,542

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

Electric Revenues

(Millions of Dollars)	2011 vs. 2010
Revenue requirements for PSCo gas generation acquisition (a)	$	124
Non-fuel riders		11
Estimated impact of weather		10
Transmission revenue		5
Conservation and DSM incentive		3
Fuel and purchased power cost recovery		(76	)
Trading, including renewable energy credit sales		(10	)
Conservation and DSM revenue (offset by expenses)		(9	)
Retail rate increase, offset by impact of seasonal rates		(8	)
Other, net		9
Total increase in electric revenues	$	59

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Electric Margin

(Millions of Dollars)	2011 vs. 2010
Revenue requirements for PSCo gas generation acquisition (a)	$	124
Non-fuel riders		11
Estimated impact of weather		10
Transmission revenue, net of costs		5
Conservation and DSM incentive		3
Conservation and DSM revenue (offset by expenses)		(9	)
Retail rate increase, offset by impact of seasonal rates		(8	)
Other, net		11
Total increase in electric margin	$	147

(a) The increase in revenue requirements for PSCo generation reflects the acquisition of the Rocky Mountain and Blue Spruce natural gas fired electric generation facilities in late 2010.  These revenue requirements are partially offset by increased O&M expense, depreciation expense, property taxes and financing costs.

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and unit 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 the natural gas revenues and margin:

(Millions of Dollars)	2011			2010
Natural gas revenues	$	1,088		$	1,075
Cost of natural gas sold and transported		(692	)		(685	)
Natural gas margin	$	396		$	390

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

Natural Gas Revenues

(Millions of Dollars)	2011 vs. 2010
Purchased natural gas adjustment clause recovery	$	8
Estimated impact of weather		5
Return on gas in storage		4
Retail rate increase		3
Retail sales decrease (excluding weather impact)		(7	)
Conservation and DSM incentive		(3	)
Conservation and DSM revenue (offset by expenses)		(2	)
Other, net		5
Total increase in natural gas revenues	$	13

Natural Gas Margin

(Millions of Dollars)	2011 vs. 2010
Estimated impact of weather	$	5
Return on gas in storage		4
Retail rate increase		3
Retail sales decrease (excluding weather impact)		(7	)
Conservation and DSM incentive		(3	)
Conservation and DSM revenue (offset by expenses)		(2	)
Other, net		6
Total increase in natural gas margin	$	6

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Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased by approximately $57.4 million, or 8.5 percent for 2011, compared to 2010.  The following summarizes the components of the changes in O&M expenses for the year ended Dec. 31:

(Millions of Dollars)	2011 vs. 2010
Higher plant generation costs	$	21
Higher labor and contract labor costs		10
Higher employee benefit costs		12
Higher rent expense		5
Higher consulting costs		3
Other, net		6
Total increase in operating and maintenance expenses	$	57

· Higher plant generation costs are attributable to incremental costs associated with new generation placed in service.

· Higher labor and contract labor costs are primarily due to maintenance on distribution facilities and the impact of annual wage increases.

· Higher employee benefit costs are largely driven by higher pension expense.

DSM Program Expenses —DSM program expenses decreased by approximately $13.9 million, or 10.8 percent, for 2011 compared with 2010.  The lower expense was primarily attributable to the timing of and a reduction in historical amortization of DSM programs.  PSCo has established DSM incentive programs designed to encourage its retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas and/or electric system.  This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers.  PSCo recovers DSM program expenses concurrently through riders and base rates.

Depreciation and Amortization —Depreciation and amortization expense increased by approximately $44.4 million, or 15.6 percent, for 2011 compared with 2010.  The increase is primarily due to Comanche Unit 3 going into service in the second quarter of 2010, the acquisition of two gas generation facilities in December 2010 and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $30.3 million, or 29.3 percent, for 2011, compared with 2010.  The increase is primarily due to an increase in property taxes in Colorado.

Other Income, Net —Other income, net, decreased by approximately $22.1 million for 2011, compared with 2010.  The decrease is primarily due to the COLI settlement in July 2010.

AFUDC — AFUDC decreased by approximately $5.6 million for 2011 compared with 2010.  The decrease is primarily due to lower AFUDC rates and lower average CWIP.  The lower average CWIP is attributed to Comanche Unit 3 going into service in 2010.

Interest Charges —Interest charges increased by approximately $14.9 million, or 8.7 percent, for 2011 compared with 2010.  The increase is primarily due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense decreased $0.8 million for 2011, compared with 2010.  The higher income tax expense for 2010 was primarily due to $7.7 million tax expense at PSRI related to the COLI Tax Court proceedings and $9.9 million tax expense related to Medicare Part D subsidies in 2010. These were partially offset by decreased state tax benefit in 2011 and the non-taxability of the Provident settlement received in 2010. The effective tax rate was 36.5 percent for 2011, compared with 36.4 percent for 2010.

The effective tax rate for 2011 differs from the statutory federal income tax rate, primarily due to state income tax expense.  The effective tax rate for 2010 differs from the statutory federal income tax rate, primarily due to state income tax expense, the COLI Tax Court proceedings, and a write-off of tax benefit previously recorded for Medicare Part D subsidies.  These were partially offset by the non-taxability of the Provident settlement.  See Note 7 to the consolidated financial statements for further discussion.

28

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 or gain that may occur as a result of 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 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.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various short-term 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 the marketing activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

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

(Thousands of Dollars)	2011			2010
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	1,817		$	651
Contracts realized or settled during the period		(1,637	)		3,811
Unrealized commodity trading transactions during the period		1,084			(2,645	)
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	1,264		$	1,817

At Dec. 31, 2011, the fair values by source for the commodity trading net asset balances 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		474	790		-	-	1,264

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

At Dec. 31, 2011, 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 short-term 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.

29

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
2011		$	0.09		$	3.00		$	0.14		$	0.33		$	0.04
2010			0.15			3.00			0.22			0.64			0.03

Interest Rate Risk — PSCo is subject to the risk of fluctuating interest rates in the normal course of business.  PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.  At Dec. 31, 2011, PSCo had unsettled interest rate swaps outstanding with a notional amount of $250 million related to an expected 2012 debt issuance.

At Dec. 31, 2011, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would have an immaterial impact on interest expense. See Note 10 to the consolidated financial statements for a discussion of PSCo’s interest rate derivatives.

Credit Risk — PSCo is also exposed to credit risk.  Credit risk relates to the risk of loss resulting from counterparties’ nonperformance of 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, 2011, a 10 percent increase in prices would have resulted in an increase in credit exposure of $2.2 million, while a decrease of 10 percent in prices would have resulted in a decrease 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 financial markets could increase PSCo’s credit risk.

Fair Value Measurements

PSCo follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and generally requires that the most observable inputs available be used for fair value measurements.  See Note 10 to the consolidated financial statements for further discussion on 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, 2011.  Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues as necessary.  Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  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 this credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2011.

Commodity derivative assets and liabilities assigned to Level 3 consist primarily of forwards and options that are either long-term in nature or related to certain commodities and delivery points with limited observability. Determining the fair value of these commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or subjective 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, 2011.

Item 8 — Financial Statements and Supplementary Data

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

See Note 16 to the consolidated financial statements for summarized quarterly financial data.

30

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 control over financial reporting as of Dec. 31, 2011.  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. Based on our assessment, we believe that, as of Dec. 31, 2011, PSCo’s internal control over financial reporting is effective 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. 27, 2012	Feb. 27, 2012

31

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder

Public Service Company of Colorado

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income, common stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011.  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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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

Feb. 27, 2012

32

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2011			2010			2009
Operating revenues
Electric	$	3,114,370		$	3,055,045		$	2,678,578
Natural gas		1,087,749			1,075,446			1,093,959
Steam and other		38,683			33,879			35,772
Total operating revenues		4,240,802			4,164,370			3,808,309
Operating expenses
Electric fuel and purchased power		1,425,173			1,513,334			1,399,541
Cost of natural gas sold and transported		692,096			685,210			712,079
Cost of sales — steam and other		17,552			16,995			15,426
Operating and maintenance expenses		734,729			677,359			628,999
Demand side management program expenses		115,078			128,939			104,919
Depreciation and amortization		328,582			284,139			256,062
Taxes (other than income taxes)		133,660			103,342			95,612
Total operating expenses		3,446,870			3,409,318			3,212,638
Operating income		793,932			755,052			595,671
Other income, net		7,001			29,117			4,696
Allowance for funds used during construction —  equity		7,710			11,370			41,118
Interest charges and financing costs
Interest charges — includes other financing costs of $6,883, $5,649, and $5,686, respectively		186,885			171,945			166,212
Allowance for funds used during construction — debt		(3,406	)		(5,307	)		(18,452	)
Total interest charges and financing costs		183,479			166,638			147,760
Income before income taxes		625,164			628,901			493,725
Income taxes		228,361			229,181			170,405
Net income	$	396,803		$	399,720		$	323,320

See Notes to Consolidated Financial Statements

33

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2011			2010			2009
Operating activities
Net income	$	396,803		$	399,720		$	323,320
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		333,960			289,050			260,935
Demand side management program amortization		7,876			19,666			27,625
Deferred income taxes		226,555			154,861			197,348
Amortization of investment tax credits		(2,613	)		(2,693	)		(2,375	)
Allowance for equity funds used during construction		(7,710	)		(11,370	)		(41,118	)
Provision for bad debts		20,371			21,571			21,189
Net derivative losses (gains)		12,102			(23,112	)		42,896
Changes in operating assets and liabilities:
Accounts receivable		(22,962	)		16,807			7,082
Accrued unbilled revenues		(7,009	)		16,418			40,573
Inventories		(30,939	)		34,424			(19,700	)
Prepayments and other		26,152			14,328			(44,555	)
Accounts payable		40,754			(106,632	)		(32,982	)
Net regulatory assets and liabilities		46,334			17,098			(64,251	)
Other current liabilities		29,843			16,067			(1,531	)
Pension and other employee benefit obligations		(84,181	)		(29,820	)		(216,696	)
Change in other noncurrent assets		4,116			(2,578	)		375
Change in other noncurrent liabilities		(15,039	)		(11,474	)		(24,796	)
Net cash provided by operating activities		974,413			812,331			473,339
Investing activities
Utility capital/construction expenditures		(726,830	)		(571,746	)		(627,421	)
Allowance for equity funds used during construction		7,710			11,370			41,118
Acquisition of generation assets		-			(732,495	)		-
Investments in utility money pool		(609,300	)		(831,000	)		(274,200	)
Repayments from utility money pool		557,300			831,000			274,200
Net cash used in investing activities		(771,120	)		(1,292,871	)		(586,303	)
Financing activities
Proceeds from (repayments of) short-term borrowings, net		(269,400	)		174,400			55,000
Proceeds from issuance of long-term debt		246,305			395,313			394,570
Repayments of long-term debt, including reacquisition premiums		-			-			(200,000	)
Borrowings under utility money pool arrangement		203,800			255,500			802,800
Repayments under utility money pool arrangement		(203,800	)		(339,500	)		(759,800	)
Capital contributions from parent		60,800			260,116			108,813
Dividends paid to parent		(270,147	)		(265,806	)		(266,188	)
Net cash (used in) provided by financing activities		(232,442	)		480,023			135,195
Net change in cash and cash equivalents		(29,149	)		(517	)		22,231
Cash and cash equivalents at beginning of period		32,912			33,429			11,198
Cash and cash equivalents at end of period	$	3,763		$	32,912		$	33,429
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(172,266	)	$	(156,906	)	$	(147,186	)
Cash received (paid) for income taxes, net		28,525			(63,999	)		(6,155	)
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	59,094		$	96,359		$	13,332
Storage assets under capital lease		7,375			12,628			143,105

See Notes to Consolidated Financial Statements

34

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	Dec. 31
	2011			2010
Assets
Current assets
Cash and cash equivalents	$	3,763		$	32,912
Accounts receivable, net		317,039			305,469
Accounts receivable from affiliates		12,063			21,042
Investments in utility money pool arrangement		52,000			-
Accrued unbilled revenues		304,544			297,535
Inventories		253,997			223,058
Regulatory assets		196,311			176,596
Deferred income taxes		33,349			13,877
Derivative instruments		4,930			6,294
Prepayments and other		19,504			54,235
Total current assets		1,197,500			1,131,018
Property, plant and equipment, net		9,475,571			9,200,556
Other assets
Regulatory assets		809,011			824,205
Derivative instruments		15,357			18,035
Other		36,066			55,016
Total other assets		860,434			897,256
Total assets	$	11,533,505		$	11,228,830
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	605,633		$	6,970
Short-term debt		-			269,400
Accounts payable		362,580			382,380
Accounts payable to affiliates		48,371			28,270
Regulatory liabilities		68,809			50,018
Taxes accrued		116,376			94,321
Accrued interest		53,749			48,866
Dividend payable to parent		66,926			66,828
Derivative instruments		85,518			29,047
Other		75,671			100,984
Total current liabilities		1,483,633			1,077,084
Deferred credits and other liabilities
Deferred income taxes		1,775,448			1,539,583
Deferred investment tax credits		44,725			47,338
Regulatory liabilities		444,442			472,846
Asset retirement obligations		42,207			72,687
Derivative instruments		38,325			43,220
Customer advances		226,097			244,345
Pension and employee benefit obligations		222,707			303,946
Other		69,561			61,334
Total deferred credits and other liabilities		2,863,512			2,785,299
Commitments and contingencies
Capitalization
Long-term debt		2,880,642			3,228,253
Common stock – authorized 100 shares of $0.01 par value; outstanding 100 shares		-			-
Additional paid in capital		3,316,386			3,255,586
Retained earnings		1,001,709			875,151
Accumulated other comprehensive (loss) income		(12,377	)		7,457
Total common stockholder’s equity		4,305,718			4,138,194
Total liabilities and equity	$	11,533,505		$	11,228,830

See Notes to Consolidated Financial Statements

35

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

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

	Common Stock Issued									Accumulated			Total
					Additional					Other			Common
					Paid In		Retained			Comprehensive			Stockholder’s
	Shares		Par Value		Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2008		100	$	-	$	2,886,657	$	683,516		$	7,628		$	3,577,801
Net income								323,320						323,320
Net derivative instrument changes during the period, net of tax of $298											473			473
Comprehensive income for 2009														323,793
Common dividends declared to parent								(264,593	)					(264,593	)
Contribution of capital by parent						108,813								108,813
Balance at Dec. 31, 2009		100	$	-	$	2,995,470	$	742,243		$	8,101		$	3,745,814
Net income								399,720						399,720
Net derivative instrument changes during the period, net of tax of $(394)											(644	)		(644	)
Comprehensive income for 2010														399,076
Common dividends declared to parent								(266,812	)					(266,812	)
Contribution of capital by parent						260,116								260,116
Balance at Dec. 31, 2010		100	$	-	$	3,255,586	$	875,151		$	7,457		$	4,138,194
Net income								396,803						396,803
Net derivative instrument changes during the period, net of tax of $(12,149)											(19,834	)		(19,834	)
Comprehensive income for 2011														376,969
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

See Notes to Consolidated Financial Statements

36

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

	Dec. 31
	2011			2010
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2012, 7.875%	$	600,000		$	600,000
March 1, 2013, 4.875%		250,000			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
Jan. 1, 2019, 5.1% (a)		48,750			48,750
June 1, 2019, 5.125%		400,000			400,000
Nov. 15, 2020, 3.2%		400,000			400,000
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			-
Capital lease obligations, through 2060, 11.2% — 14.3%		191,374			190,223
Unamortized debt		(8,349	)		(8,250	)
Total		3,486,275			3,235,223
Less current maturities		605,633			6,970
Total long-term debt	$	2,880,642		$	3,228,253
Common Stockholder’s Equity
Common stock — 100 shares authorized of $0.01 par value, 100 shares outstanding at Dec. 31, 2011 and 2010, respectively	$	-		$	-
Additional paid-in capital		3,316,386			3,255,586
Retained earnings		1,001,709			875,151
Accumulated comprehensive (loss) income		(12,377	)		7,457
Total common stockholder’s equity	$	4,305,718		$	4,138,194

(a) Pollution control financing

See Notes to Consolidated Financial Statements

37

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, purchased power agreements and fuel contracts to determine if the other party is a variable interest entity and if so, 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, decommissioning, 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 such 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 in the period the write-offs are recorded.  See Note 13 for further discussion of regulatory assets and liabilities.

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

PSCo has various rate-adjustment mechanisms in place that currently provide for the recovery of natural gas and electric fuel costs, as well as purchased energy costs.  These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred.  Where applicable, under governing state 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.

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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, but are not limited to, commercial process efficiency and lighting updates, and rebates for participation in air conditioner interruption and energy-efficient appliances.

The costs incurred for DSM programs are deferred if it is probable that future revenue, in an amount at least equal to the deferred amount, will be provided to permit recovery of the previously incurred cost, rather than to provide for expected future amounts of similar programs. 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 applicable interest expense.  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 units of property are charged to operating expenses as incurred.  Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate.  Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable.  Upon regulatory approval of deferred accounting for accelerated depreciation expenses, property, plant and equipment that is to be early decommissioned is reclassified as plant to be retired.

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 2.6 percent, 2.5 percent and 2.6 percent, for the years ended Dec. 31, 2011, 2010 and 2009, respectively.

Leases — PSCo evaluates a variety of contracts for lease classification at inception, including purchased power agreements 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 pretax rate to qualified CWIP.  The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital).  AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates.

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases the CPUC has approved a more current recovery of cost associated with large capital projects, resulting in a lower recognition of AFUDC.  One such project was the Comanche Unit 3 steam generation plant completed in 2010.  A current recovery of construction costs is provided for any transmission assets in CWIP at the end of each year through the TCA rider.

Asset Retirement Obligations— 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 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 asset retirement obligations and related capitalized costs, and a regulatory liability is recognized for such future expenditures.

See Note 12 for further discussion of asset retirement obligations.

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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, based on the weight of available evidence, 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 positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations, is considered.

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., as parent of the Xcel Energy consolidated group, 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 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.

Gains or losses on hedging transactions for the sale of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; 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.

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 as normal purchases or normal sales.

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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.

Renewable Energy Credits — RECs aremarketable environmental commodities 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.  Currently, PSCo acquires RECs from the generation or purchase of renewable power.

When RECs are acquired in the course of generation or purchased as a result of meeting load obligations, 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 the cost of future compliance requirements that are recoverable in future rates as regulatory assets.

Sales of RECs that are acquired in the course of generation or purchased as a result of meeting load obligations 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.  RECs acquired for trading purposes are recorded as other investments and are also recorded at cost.  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 at no cost from the EPA, are recorded at cost plus associated broker commission fees.  PSCo follows the inventory accounting model for all emission allowances.  The 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 the 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.

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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 — Xcel Energy 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 the regulatory recovery mechanisms of Xcel Energy Inc.’s utility subsidiaries, 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.  See Note 12 for specific details of issued guarantees.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2011 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2. Accounting Pronouncements

Recently Issued

Fair Value Measurement — In May 2011, the FASB issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU No. 2011-04), which provides additional guidance for fair value measurements.  These updates to the Codification include clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity.  These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011.  PSCo does not expect the implementation of this guidance to have a material impact on its consolidated financial statements.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which updates the Codification to require the presentation of the components of net income, the components of OCI and total comprehensive income in either a single continuous statement of comprehensive income or in two separate, but consecutive statements of net income and comprehensive income.  These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income.  These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011.  PSCo does not expect the implementation of this presentation guidance to have a material impact on its consolidated financial statements.

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which updates the Codification to require 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.  These updates to the disclosure requirements of the Codification do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those periods.  PSCo does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

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3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2011			Dec. 31, 2010
Accounts receivable, net
Accounts receivable	$	341,737		$	329,523
Less allowance for bad debts		(24,698	)		(24,054	)
	$	317,039		$	305,469
Inventories
Materials and supplies	$	53,318		$	51,615
Fuel		94,874			67,187
Natural gas		105,805			104,256
	$	253,997		$	223,058
Property, plant and equipment, net
Electric plant	$	9,469,434		$	9,003,103
Natural gas plant		2,456,275			2,284,212
Common and other property		763,513			757,059
Plant to be retired (a)		151,184			236,606
Construction work in progress		242,095			231,636
Total property, plant and equipment		13,082,501			12,512,616
Less accumulated depreciation		(3,606,930	)		(3,312,060	)
	$	9,475,571		$	9,200,556

(a) In 2010, in response to the CACJA, the CPUC approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017.  Amounts are presented net of accumulated depreciation.  See Item 1 –  Public Utility Regulation for further discussion.

4.    Borrowings and Other Financing Instruments

Short-Term Borrowings

Commercial Paper— PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility with a borrowing limit of $700 million, of which there were no borrowings outstanding during the three months ended Dec. 31, 2011.  Commercial paper outstanding for PSCo was as follows:

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2011			Twelve Months Ended Dec. 31, 2010			Twelve Months Ended Dec. 31, 2009
Borrowing limit	$	700		$	675		$	675
Amount outstanding at period end		-			269			95
Average amount outstanding		73			49			9
Maximum amount outstanding		304			275			105
Weighted average interest rate, computed on a daily basis		0.37	%		0.37	%		0.70	%
Weighted average interest rate at end of period		N/A			0.42			0.35

Credit Facilities — 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 the credit agreement.

During 2011, PSCo executed a new four-year credit agreement.  The total size of the credit facility is $700 million and terminates in March 2015.  PSCo has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

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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.  Other features of PSCo’s credit facility include:

· The credit facility may be increased by up to $100 million.

· The credit facility has a financial covenant requiring that PSCo’s 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, 2011. 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 the Eurodollar rate or an alternate base rate, plus a borrowing margin of 0 to 200 basis points per year based on the applicable credit ratings.

· The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the line of credit at a range of 10 to 35 basis points per year.

At Dec. 31, 2011, PSCo had the following committed credit facility available (in millions):

Credit Facility		Drawn (a)		Available
$	700.0	$	4.9	$	695.1

(a) 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, 2011 and 2010.

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, 2011 and 2010, there were $4.9 million and $4.7 million of letters of credit outstanding, respectively.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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. With a borrowing limit of $250 million, PSCo had no borrowings outstanding during the three months ended Dec. 31, 2011.  Money pool borrowings outstanding for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2011			Twelve Months Ended Dec. 31, 2010			Twelve Months Ended Dec. 31, 2009
Borrowing limit	$	250		$	250		$	250
Amount outstanding at period end		-			-			84
Average amount outstanding		3			8			28
Maximum amount outstanding		53			84			145
Weighted average interest rate, computed on a daily basis		0.35	%		0.33	%		1.10	%
Weighted average interest rate at end of period		N/A			N/A			0.36

Long-Term Borrowings

Generally, all real and personal property used in or in connection with the electric utility business of PSCo is subject to the liens of its first mortgage indentures.  Additionally, 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 August 2011, PSCo issued $250 million of 4.75 percent first mortgage bonds due Aug. 15, 2041.  In November 2010, PSCo issued $400 million of 3.2 percent first mortgage bonds, due Nov. 15, 2020.

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Maturities of long-term debt are as follows:

(Millions of Dollars)
2012	$	606
2013		257
2014		282
2015		8
2016		8

PSCo plans to refinance the current portion of long-term debt coming due in 2012.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $18.5 million and $18.3 million, net of amortization, at Dec. 31, 2011 and 2010, respectively.  PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

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

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, 2011:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership %
Electric Generation:
Hayden Unit 1	$	88,337	$	60,549	$	830		75.5	%
Hayden Unit 2		119,621		55,126		722		37.4
Hayden Common Facilities		34,558		14,155		1		53.1
Craig Units 1 and 2		54,058		33,225		193		9.7
Craig Common Facilities 1, 2 and 3		35,241		15,896		2,863		6.5 - 9.7
Comanche Unit 3		867,976		28,973		1,014		66.7
Comanche Common Facilities		12,628		219		169		82.0
Electric Transmission:
Transmission and other facilities, including substations		150,420		56,654		449	Various
Gas Transportation:
Rifle to Avon		16,278		6,333		-		60.0
Total	$	1,379,117	$	271,130	$	6,241

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

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7.     Income Taxes

COLI — In 2007, Xcel Energy Inc., PSCo and the U.S. government settled an ongoing dispute regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees.  These COLI policies were owned and managed by PSRI.  Xcel Energy Inc. and PSCo paid the U.S. government a total of $64.4 million in settlement of the U.S. government’s claims for tax, penalty and interest for tax years 1993 through 2007.  Xcel Energy Inc. and PSCo surrendered the policies to its insurer on Oct. 31, 2007, without recognizing a taxable gain.  As a result of the settlement, the lawsuit filed by Xcel Energy Inc. and PSCo in the U.S. District Court was dismissed and the Tax Court proceedings were dismissed in December 2010 and January 2011.

As part of the Tax Court proceedings, during 2010, an agreement in principle of Xcel Energy Inc.’s and PSCo’s statements of account was reached, dating back to tax year 1993.  Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $9.4 million. Upon final cash settlement in 2011, Xcel Energy received $0.7 million and recognized a further reduction of expense of $0.3 million.  A closing agreement covering tax years 2003 through 2007 was finalized with the IRS in January 2012.

In 2010, Xcel Energy Inc., PSCo and PSRI entered into a settlement agreement with Provident related to all claims asserted by Xcel Energy Inc., PSCo and PSRI against Provident in a lawsuit associated with the discontinued COLI program.  Under the terms of the settlement, Xcel Energy Inc., PSCo and PSRI were paid $25 million by Provident and Reassure America Life Insurance Company in 2010.  The $25 million proceeds were not subject to income taxes.

Medicare Part D Subsidy Reimbursements — 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.  Based on this provision, PSCo became subject to additional taxes and was required to reverse previously recorded tax benefits in the period of enactment.  As a result, PSCo expensed approximately $9.9 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010.  PSCo does not expect the $9.9 million of additional tax expense to recur in future periods.

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 2007 federal income tax return expired in September 2011.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012.  The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010.   In December 2011, Xcel Energy finalized the Revenue Agent Report and signed the Waiver of Assessment for tax years 2008 and 2009.  The total assessment for these tax years was $1.4 million, including tax and interest.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Dec. 31, 2011, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006.  As of Dec. 31, 2011, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	Dec. 31, 2011		Dec. 31, 2010
Unrecognized tax benefit — Permanent tax positions	$	0.5	$	1.3
Unrecognized tax benefit — Temporary tax positions		10.9		10.3
Unrecognized tax benefit balance	$	11.4	$	11.6

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

(Millions of Dollars)	2011			2010			2009
Balance at Jan. 1	$	11.6		$	7.2		$	10.3
Additions based on tax positions related to the current year		3.4			4.1			3.7
Reductions based on tax positions related to the current year		(0.8	)		(0.2	)		(0.3	)
Additions for tax positions of prior years		5.8			1.6			2.2
Reductions for tax positions of prior years		(0.9	)		(1.1	)		(0.5	)
Settlements with taxing authorities		(7.7	)		-			(8.2	)
Balance at Dec. 31	$	11.4		$	11.6		$	7.2

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 carryfowards are as follows:

(Millions of Dollars)	Dec. 31, 2011			Dec. 31, 2010
NOL and tax credit carryforwards	$	(3.7	)	$	(7.2	)

The decrease in the unrecognized tax benefit balance of $0.2 million in 2011 was due to the resolution of certain federal audit matters, partially offset by an increase due to the addition of uncertain tax positions related to current and prior years’ activity.  PSCo’s amount of unrecognized tax benefits could change in the next 12 months as the IRS and state audits resume.  At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.  However, PSCo does not anticipate total unrecognized tax benefits will significantly change within the next 12 months.

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

(Millions of Dollars)	2011			2010			2009
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.1	)	$	(0.1	)	$	(0.4	)
Interest (expense) income related to unrecognized tax benefits		(0.2	)		-			0.3
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(0.3	)	$	(0.1	)	$	(0.1	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2011, 2010 or 2009.

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)	2011		2010
Federal NOL carryforward	$	391.6	$	150.5
Federal tax credit carryforwards		15.5		14.6
State NOL carryforward		566.8		298.2
State tax credit carryforwards, net of federal detriment		9.4		8.4

The federal carryforward periods expire between 2021 and 2031.  The state carryforward periods expire between 2012 and 2031.

47

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:

	2011			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit		2.1			1.1			3.3
Resolution of income tax audits and other		0.4			1.2			0.1
Tax credits recognized, net of federal income tax expense		(0.8	)		(0.8	)		(1.0	)
Regulatory differences — utility plant items		(0.2	)		(0.5	)		(2.7	)
Change in unrecognized tax benefits		(0.1	)		-			(0.1	)
Previously recognized Medicare Part D subsidies		(0.1	)		1.6			-
Life insurance policies		-			(1.4	)		-
Other, net		0.2			0.2			(0.1	)
Effective income tax rate		36.5	%		36.4	%		34.5	%

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

(Thousands of Dollars)	2011			2010			2009
Current federal tax expense (benefit)	$	1,889		$	76,228		$	(20,867	)
Current state tax benefit		(796	)		(461	)		(2,327	)
Current change in unrecognized tax expense (benefit)		3,326			1,246			(1,374	)
Deferred federal tax expense		208,481			147,704			172,454
Deferred state tax expense		24,894			11,180			27,508
Deferred change in unrecognized tax (benefit) expense		(4,059	)		(920	)		864
Deferred tax credits		(2,761	)		(3,103	)		(3,478	)
Deferred investment tax credits		(2,613	)		(2,693	)		(2,375	)
Total income tax expense	$	228,361		$	229,181		$	170,405

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

(Thousands of Dollars)	2011			2010			2009
Deferred tax expense excluding items below	$	216,393		$	160,543		$	224,484
Tax benefit (expense) allocated to other comprehensive income and other		12,149			393			(298	)
Amortization and adjustments to deferred income taxes onincome tax regulatory assets and liabilities		(1,987	)		(6,075	)		(26,838	)
Deferred tax expense	$	226,555		$	154,861		$	197,348

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

(Thousands of Dollars)	2011		2010
Deferred tax liabilities:
Difference between book and tax bases of property	$	1,823,058	$	1,527,296
Employee benefits		130,544		105,578
Other		113,489		122,856
Total deferred tax liabilities	$	2,067,091	$	1,755,730
Deferred tax assets:
NOL carryforward	$	169,688	$	73,948
Unbilled revenue — fuel costs		61,118		59,182
Tax credit carryforward		24,972		22,983
Deferred investment tax credits		16,985		17,989
Regulatory liabilities		14,693		18,249
Litigation reserve		258		11,433
Other		37,278		26,240
Total deferred tax assets	$	324,992	$	230,024
Net deferred tax liability	$	1,742,099	$	1,525,706

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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 76 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements.  At Dec. 31, 2011, PSCo had 2,122 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 hierarchal 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, such as common stocks listed by the New York Stock Exchange.

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, such as corporate bonds with pricing based on market interest rate curves and recent trades of similarly rated securities.

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, such as private equity investments and real estate investments, for which the measurement of net asset value requires significant use of unobservable inputs when determining the fair value of the underlying fund investments, including equity in non-publicly traded entities and real estate properties.

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.

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 actual historical returns achieved by its 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 above the assumed levels of 7.00, 7.84 and 8.50 percent in 2011, 2010 and 2009, respectively.  Xcel Energy Inc. and PSCo continually review the pension assumptions.  In 2012, PSCo’s estimated investment-return assumption is 6.65 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; however, as PSCo has experienced in recent years, unusual market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

49

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

	2011			2010
Domestic and international equity securities		23	%		19	%
Long-duration fixed income securities		31			54
Short-to-intermediate term fixed income securities		10			8
Alternative investments		33			13
Cash		3			6
Total		100	%		100	%

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

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2011 and 2010:

	Dec. 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	60,405	$	-		$	-	$	60,405
Derivatives		-		3,101			-		3,101
Government securities		-		190,555			-		190,555
Corporate bonds		-		210,182			-		210,182
Asset-backed securities		-		-			9,824		9,824
Mortgage-backed securities		-		-			23,614		23,614
Common stock		20,793		-			-		20,793
Private equity investments		-		-			49,489		49,489
Commingled funds		-		410,243			-		410,243
Real estate		-		-			11,230		11,230
Securities lending collateral obligation and other		-		(20,229	)		-		(20,229	)
Total	$	81,198	$	793,852		$	94,157	$	969,207

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	81,485	$	-		$	-	$	81,485
Derivatives		-		2,821			-		2,821
Government securities		-		44,883			-		44,883
Corporate bonds		-		222,531			-		222,531
Asset-backed securities		-		-			8,399		8,399
Mortgage-backed securities		-		-			36,134		36,134
Common stock		35,960		-			-		35,960
Private equity investments		-		-			36,420		36,420
Commingled funds		-		384,910			-		384,910
Real estate		-		-			21,962		21,962
Securities lending collateral obligation and other		-		(26,036	)		-		(26,036	)
Total	$	117,445	$	629,109		$	102,915	$	849,469

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The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2011, 2010 and 2009:

(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			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
Real estate		21,962		(190	)		6,000			(16,542	)		11,230
Private equity investments		36,420		1,229			3,925			7,915			49,489
Total	$	102,915	$	2,072		$	7,407		$	(18,237	)	$	94,157

(Thousands of Dollars)	Jan. 1, 2010		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Dec. 31, 2010
Asset-backed securities	$	14,333	$	1,014		$	(782	)	$	(6,166	)	$	8,399
Mortgage-backed securities		44,296		4,127			(4,201	)		(8,088	)		36,134
Real estate		19,838		(338	)		2,375			87			21,962
Private equity investments		24,415		(300	)		4,696			7,609			36,420
Total	$	102,882	$	4,503		$	2,088		$	(6,558	)	$	102,915

(Thousands of Dollars)	Jan. 1, 2009		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			Dec. 31, 2009
Asset-backed securities	$	20,499	$	708		$	11,990		$	(18,864	)	$	14,333
Mortgage-backed securities		44,115		1,642			5,193			(6,654	)		44,296
Real estate		28,934		(169	)		(12,522	)		3,595			19,838
Private equity investments		21,453		-			(2,879	)		5,841			24,415
Total	$	115,001	$	2,181		$	1,782		$	(16,082	)	$	102,882

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)	2011			2010
Accumulated Benefit Obligation at Dec. 31	$	1,036,749		$	955,109
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	971,805		$	897,707
Service cost		17,726			16,142
Interest cost		52,234			52,639
Plan amendments		-			11
Actuarial loss		66,766			61,776
Benefit payments		(61,158	)		(56,470	)
Obligation at Dec. 31	$	1,047,373		$	971,805
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	849,469		$	806,809
Actual return on plan assets		120,325			99,130
Employer contributions		60,571			-
Benefit payments		(61,158	)		(56,470	)
Fair value of plan assets at Dec. 31	$	969,207		$	849,469
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(78,166	)	$	(122,336	)

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

51

(Thousands of Dollars)	2011			2010
PSCo Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	450,405		$	464,143
Prior service credit		(22,636	)		(22,414	)
Total	$	427,769		$	441,729
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	36,052		$	27,216
Noncurrent regulatory assets		391,717			414,513
Total	$	427,769		$	441,729
Measurement Date	Dec. 31, 2011			Dec. 31, 2010
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.00	%		5.50	%
Expected average long-term increase in compensation level		4.00			4.00
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 and 2012 to meet minimum funding requirements.

The Pension Protection Act changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2010 through 2012:

· In January 2012, contributions of $190.5 million were made across four of Xcel Energy’s pension plans, of which $41.0 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;

· In 2010, contributions of $34 million were made to the Xcel Energy Pension Plan, of which none was attributable to PSCo.

· For future years, we anticipate contributions will be made as necessary.

Plan Amendments — No amendments occurred during 2011 to the Xcel Energy pension plans.

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

(Thousands of Dollars)	2011			2010			2009
Service cost	$	17,726		$	16,142		$	15,557
Interest cost		52,234			52,639			54,745
Expected return on plan assets		(67,946	)		(73,609	)		(71,435	)
Amortization of prior service cost		222			204			4,167
Amortization of net loss		28,126			19,927			10,813
Net periodic pension cost	$	30,362		$	15,303		$	13,847
Significant Assumptions Used to Measure Costs:
Discount rate		5.50	%		6.00	%		6.75	%
Expected average long-term increase in compensation level		4.00			4.00			4.00
Expected average long-term rate of return on assets		7.00			7.84			8.50

52

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.  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 2012 pension cost calculations will be 6.65 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.

Xcel Energy, which includes PSCo, also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel.  Benefits for these unfunded plans are paid out of operating cash flows.

Defined Contribution Plans

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees.  The contributions for PSCo were approximately $8.5 million in 2011, $8.4 million in 2010 and $6.4 million in 2009.

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 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.  PSCo transitioned to full accrual accounting for postretirement benefit costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises.  The Colorado jurisdictional postretirement benefit costs deferred during the transition period are being 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 assumption 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.  Investment-return volatility is not considered to be a material factor in postretirement health care costs.

53

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, 2011 and 2010:

	Dec. 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	51,203	$	-		$	-	$	51,203
Derivatives		-		11,608			-		11,608
Government securities		-		57,937			-		57,937
Corporate bonds		-		54,244			-		54,244
Asset-backed securities		-		-			6,941		6,941
Mortgage-backed securities		-		-			24,038		24,038
Preferred stock		-		373			-		373
Common stock		351		-			-		351
Private equity investments		-		-			479		479
Commingled funds		-		178,951			-		178,951
Real estate		-		-			144		144
Securities lending collateral obligation and other		-		(9,761	)		-		(9,761	)
Total	$	51,554	$	293,352		$	31,602	$	376,508

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	131,220	$	-	$	-	$	131,220
Derivatives		-		11,922		-		11,922
Government securities		-		3,681		-		3,681
Corporate bonds		-		62,822		-		62,822
Asset-backed securities		-		-		2,427		2,427
Mortgage-backed securities		-		-		17,461		17,461
Preferred stock		-		441		-		441
Common stock		1,022		-		-		1,022
Private equity investments		-		-		1,018		1,018
Commingled funds		-		93,333		-		93,333
Real estate		-		-		614		614
Securities lending collateral obligation and other		-		51,870		-		51,870
Total	$	132,242	$	224,069	$	21,520	$	377,831

The following tables present the changes in PSCo’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2011, 2010 and 2009:

(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, Net			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
Real estate		614		(2	)		206			(674	)		144
Private equity investments		1,018		12			9			(560	)		479
Total	$	21,520	$	(1,467	)	$	950		$	10,599		$	31,602

(Thousands of Dollars)	Jan. 1, 2010		Net Realized (Losses)			Net Unrealized (Losses)		Purchases, Issuances, and Settlements, Net			Dec. 31, 2010
Asset-backed securities	$	7,491	$	(198	)	$	680	$	(5,546	)	$	2,427
Mortgage-backed securities		41,594		(698	)		3,092		(26,527	)		17,461
Real estate		556		(9	)		67		-			614
Private equity investments		684		(8	)		131		211			1,018
Total	$	50,325	$	(913	)	$	3,970	$	(31,862	)	$	21,520

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(Thousands of Dollars)	Jan. 1, 2009		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, net			Dec. 31, 2009
Asset-backed securities	$	7,950	$	23		$	1,434		$	(1,916	)	$	7,491
Mortgage-backed securities		60,332		676			2,634			(22,048	)		41,594
Real estate		911		(5	)		(355	)		5			556
Private equity investments		676		-			(45	)		53			684
Total	$	69,869	$	694		$	3,668		$	(23,906	)	$	50,325

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

(Thousands of Dollars)	2011			2010
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	543,484		$	478,325
Service cost		3,625			2,965
Interest cost		28,391			28,139
Medicare subsidy reimbursements		1,977			2,769
ERRP proceeds shared with retirees		371			-
Amendments		(23,704	)		-
Plan participants’ contributions		3,667			3,268
Actuarial (gain) loss		(15,784	)		61,045
Benefit payments		(34,293	)		(33,027	)
Obligation at Dec. 31	$	507,734		$	543,484
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	377,831		$	330,303
Actual return on plan assets		545			46,764
Plan participants’ contributions		3,667			3,268
Employer contributions		28,758			30,523
Benefit payments		(34,293	)		(33,027	)
Fair value of plan assets at Dec. 31	$	376,508		$	377,831
Funded Status at Dec. 31:
Funded status (a)	$	(131,226	)	$	(165,653	)

PSCo Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	142,631		$	141,944
Prior service credit		(43,140	)		(22,349	)
Transition obligation		11,789			22,793
Total	$	111,280		$	142,388
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	21,623		$	17,231
Noncurrent regulatory assets		89,657			125,157
Total	$	111,280		$	142,388
Measurement Date	Dec. 31, 2011			Dec. 31, 2010
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.00	%		5.50	%
Mortality table	RP 2000			RP 2000
Health care costs trend rate — initial		6.31	%		6.50	%

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

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Effective Dec. 31, 2011, the ultimate trend assumption remained unchanged at 5.0 percent.  The period until the ultimate rate is reached remained unchanged at eight years.  Xcel Energy 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 1-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		$	52,098	$	(42,610	)
Service and interest components			3,821		(3,042	)

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 $49.0 million and $48.4 million during 2011 and 2010, of which $28.8 million and $30.5 million were attributable to PSCo.  Xcel Energy expects to contribute approximately $39.1 million during 2012, of which $20.2 million is attributable to PSCo.

Plan Amendments — The 2011 decrease of the projected Xcel Energy postretirement health and welfare benefit obligation for plan amendments is due to changes in the participant co-pay structure for certain retiree groups and the elimination of dental and vision benefits for some non-bargaining retirees.

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

(Thousands of Dollars)	2011			2010			2009
Service cost	$	3,625		$	2,965		$	3,628
Interest cost		28,391			28,139			33,380
Expected return on plan assets		(27,961	)		(24,518	)		(19,369	)
Amortization of transition obligation		11,004			11,004			11,004
Amortization of prior service cost		(2,913	)		(2,913	)		(1,100	)
Amortization of net loss		8,942			7,629			12,734
Net periodic postretirement benefit cost		21,088			22,306			40,277
Additional cost recognized due to effects of regulation		3,891			3,891			3,891
Net benefit cost recognized for financial reporting	$	24,979		$	26,197		$	44,168
Significant Assumptions Used to Measure Costs:
Discount rate		5.50	%		6.00	%		6.75	%
Expected average long-term rate of return on assets (before tax)		7.50			7.50			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.

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
2012	$	71,063	$	35,147	$	2,350	$	32,797
2013		69,194		35,380		2,532		32,848
2014		72,259		36,485		2,691		33,794
2015		74,138		37,710		2,844		34,866
2016		76,973		39,109		2,988		36,121
2017-2021		401,334		207,802		17,379		190,423

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9.    Other Income, Net

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

(Thousands of Dollars)	2011			2010			2009
Interest income	$	4,860		$	3,296		$	3,247
COLI settlement (See Note 7)		-			25,000			-
Other nonoperating income		2,512			1,758			3,192
Life insurance policy expense		(359	)		(937	)		(1,348	)
Other nonoperating expense		(12	)		-			(395	)
Other income, net	$	7,001		$	29,117		$	4,696

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 hierarchal 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 discounted cash flow or option pricing 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 utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options.  Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers.

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, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

Derivative Instruments Fair Value Measurements

PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce 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, 2011, accumulated OCI related to interest rate derivatives included $1.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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At Dec. 31, 2011, PSCo had unsettled interest rate swaps outstanding with a total notional amount of $250 million.  These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various short-term 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.

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, gas for resale, and vehicle fuel.

At Dec. 31, 2011, PSCo had various vehicle fuel related contracts designated as cash flow hedges extending through December 2014.  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, 2011 and 2010.

At Dec. 31, 2011, accumulated OCI related to vehicle fuel cash flow hedges included $0.1 million 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 any amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards at Dec. 31, 2011 and Dec. 31, 2010:

(Amounts in Thousands) (a)	Dec. 31, 2011		Dec. 31, 2010
MWh of electricity		1,299	2,418
MMBtu of natural gas		32,053	59,465
Gallons of vehicle fuel		270	360

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

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

(Thousands of Dollars)	2011			2010			2009
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	7,457		$	8,101		$	7,628
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges		(18,328	)		(63	)		315
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(1,506	)		(581	)		158
Accumulated other comprehensive (loss) income related to cash flow hedges at Dec. 31	$	(12,377	)	$	7,457		$	8,101

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2011 and Dec. 31, 2010.

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The following tables detail the impact of derivative activity during the years ended Dec. 31, 2011 and 2010, on OCI, regulatory assets and liabilities and income:

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

	Dec. 31, 2010
	Fair Value Changes Recognized								Pre-Tax Amounts Reclassified into
	During the Period in:								Income During the Period from:									Pre-Tax Gains (Loss)
	Accumulated Other				Regulatory				Accumulated Other					Regulatory				Recognized
	Comprehensive				(Assets) and				Comprehensive					Assets and				During the Period
(Thousands of Dollars)	Income				Liabilities				Income					(Liabilities)				in Income
Derivatives designated as cash flow hedges
Interest rate		$	-			$	-			$	(2,336	)	(a)		$	-			$	-
Vehicle fuel and other commodity			(101	)			-				1,399		(c)			-				-
Total		$	(101	)		$	-			$	(937	)			$	-			$	-
Other derivative instruments
Trading commodity		$	-			$	-			$	-				$	-			$	(1,058	)	(b)
Natural gas commodity			-				(83,295	)			-					40,862	(d)			-
Other			-				-				-					-				135		(b)
Total		$	-			$	(83,295	)		$	-				$	40,862			$	(923	)

(a) Recorded to interest charges.

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

(c) Recorded to O&M expenses.

(d) Recorded to cost of natural gas sold and transported; these derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate.

Credit Related Contingent Features —Contract provisions of the derivative instruments that PSCo enters into 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, contracts underlying $6.9 million and $5.6 million of derivative instruments in a liability position at Dec. 31, 2011 and Dec. 31, 2010, respectively, would have required PSCo to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $9.2 million and $9.8 million, respectively.  At Dec. 31, 2011 and Dec. 31, 2010, there was no collateral posted on these specific contracts.

PSCo’s 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, 2011 and Dec. 31, 2010.

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Recurring Fair Value Measurements

The following table presents, for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	76	$	-	$	76	$	(76	)	$	-
Other derivative instruments:
Trading commodity		-		6,550		-		6,550		(3,712	)		2,838
Total current derivative assets	$	-	$	6,626	$	-	$	6,626	$	(3,788	)		2,838
Purchased power agreements (a)													2,092
Current derivative instruments												$	4,930

Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	48	$	-	$	48	$	-		$	48
Other derivative instruments:
Trading commodity		-		8,292		-		8,292		(3,305	)		4,987
Total noncurrent derivative assets	$	-	$	8,340	$	-	$	8,340	$	(3,305	)		5,035
Purchased power agreements (a)													10,322
Noncurrent derivative instruments												$	15,357

Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	29,630	$	-	$	29,630	$	-		$	29,630
Other derivative instruments:
Trading commodity		-		6,076		-		6,076		(2,846	)		3,230
Natural gas commodity		-		54,525		-		54,525		(7,410	)		47,115
Total current derivative liabilities	$	-	$	90,231	$	-	$	90,231	$	(10,256	)		79,975
Purchased power agreements (a)													5,543
Current derivative instruments												$	85,518
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	7,502	$	-	$	7,502	$	(3,305	)	$	4,197
Total noncurrent derivative liabilities	$	-	$	7,502	$	-	$	7,502	$	(3,305	)		4,197
Purchased power agreements (a)													34,128
Noncurrent derivative instruments												$	38,325

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, 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) The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between PSCo and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

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The following table presents for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2010:

	Dec. 31, 2010
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	56	$	-	$	56	$	-		$	56
Other derivative instruments:
Trading commodity		-		5,765		-		5,765		(2,633	)		3,132
Natural gas commodity		-		1,396		-		1,396		(1,019	)		377
Total current derivative assets	$	-	$	7,217	$	-	$	7,217	$	(3,652	)		3,565
Purchased power agreements (a)													2,729
Current derivative instruments												$	6,294
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	68	$	-	$	68	$	-		$	68
Other derivative instruments:
Trading commodity		-		6,770		-		6,770		(2,118	)		4,652
Natural gas commodity		-		1,111		-		1,111		(211	)		900
Total noncurrent derivative assets	$	-	$	7,949	$	-	$	7,949	$	(2,329	)		5,620
Purchased power agreements (a)													12,415
Noncurrent derivative instruments												$	18,035

Current derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	5,192	$	-	$	5,192	$	(2,669	)	$	2,523
Natural gas commodity		-		41,753		-		41,753		(20,969	)		20,784
Total current derivative liabilities	$	-	$	46,945	$	-	$	46,945	$	(23,638	)		23,307
Purchased power agreements (a)													5,740
Current derivative instruments												$	29,047
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	5,526	$	-	$	5,526	$	(2,118	)	$	3,408
Natural gas commodity		-		350		-		350		(211	)		139
Total noncurrent derivative liabilities	$	-	$	5,876	$	-	$	5,876	$	(2,329	)		3,547
Purchased power agreements (a)													39,673
Noncurrent derivative instruments												$	43,220

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, 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) The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between PSCo and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

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There were no Level 3 recurring fair value measurements at Dec. 31 2011, and 2010.  The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2010, and 2009:

	Year Ended Dec. 31
(Thousands of Dollars)	2010			2009
Balance at Jan. 1	$	804		$	(26	)
Purchases		(135	)		-
Settlements		(300	)		(3,668	)
Transfers into Level 3		-			588
Transfers out of Level 3		(1,887	)		(9	)
Net transactions recorded during the period:
Gains recognized in earnings(a)		1,518			2,535
Gains recognized as regulatory liabilities		-			1,384
Balance at Dec. 31	$	-		$	804

(a) These amounts relate to commodity derivatives held at the end of the period.

PSCo recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for the year ended Dec. 31, 2011.  The following table presents the transfers that occurred from Level 3 to Level 2 during the year ended Dec. 31, 2010.

	Year Ended
(Thousands of Dollars)	Dec. 31, 2010
Trading commodity derivatives not designated as cash flow hedges:
Current assets	$	1,888
Noncurrent assets		4,988
Current liabilities		(1,265	)
Noncurrent liabilities		(3,724	)
Total	$	1,887

There were no transfers of amounts from Level 2 to Level 3, or any transfers to or from Level 1 for the year ended Dec. 31, 2010.  The transfer of amounts from Level 3 to Level 2 in the year ended Dec. 31, 2010 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.

Fair Value of Long-Term Debt

As of Dec. 31, 2011 and 2010, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2011				2010
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,486,275	$	4,020,083	$	3,235,223	$	3,531,729

The fair value of PSCo’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.  The fair value estimates presented are based on information available to management as of Dec. 31, 2011 and 2010.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date and current estimates of fair values may differ significantly.

11.    Rate Matters

Pending and Recently Concluded Regulatory Proceedings — CPUC

Base Rate

PSCo 2010 Gas Rate Case — In December 2010, PSCo filed a request with the CPUC to increase Colorado retail gas rates by $27.5 million on an annual basis.  In March 2011, PSCo revised its requested rate increase to $25.6 million.  The revised request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.1 percent.  PSCo proposed recovering $23.2 million of test year capital and O&M expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006.  PSCo also proposed removing the earnings on gas in underground storage from base rates.

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In August 2011, the CPUC approved a comprehensive settlement that PSCo reached with the CPUC Staff and the OCC to increase rates by $12.8 million, to institute the PSIA rider, and to remove gas in underground storage from base rates and recover those costs in the GCA.  The GCA is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs.  Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent.

New base rates and the GCA recovery went into effect in September 2011.  The PSIA rider and new rate designs went into effect on Jan. 1, 2012.

PSCo 2011 Electric Rate Case —In November 2011, PSCo filed a request with the CPUC to increase Colorado retail electric rates by $141.9 million.  The request was based on a 2012 forecast test year, a 10.75 percent ROE, a rate base of $5.4 billion and an equity ratio of 56 percent.  Final rates are expected to be effective in the summer of 2012.The CPUC is expected to rule on the electric rate case in July 2012.

In November 2011, PSCo filed a petition to implement interim rates, subject to refund, of $100 million to be effective in January 2012.  On Jan. 11, 2012, the CPUC denied PSCo’s request to implement an interim electric rate increase of $100 million on the basis that it had not demonstrated adverse financial impacts.  On Jan. 12, 2012, PSCo filed for reconsideration of the CPUC’s decision to deny interim rates, and requested that the CPUC authorize interim rates of approximately $42 million, specifically related to the impacts resulting from the expiration of the Black Hills contract.  On Jan. 17, 2012, the CPUC denied the request for reconsideration.  However, on Jan. 27, 2012, the CPUC approved PSCo’s request for deferred accounting of the $42 million annual revenue requirement associated with the Black Hills contract.

Pending Regulatory Proceedings — FERC

Base Rate

PSCo Wholesale Electric Rate Case — In February 2011, PSCo filed with the FERC to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011.  The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent.  The formula rate would be estimated each year for the following year and then trued-up to actual costs after the conclusion of the calendar year.  A decision is expected in the first quarter of 2012.

Electric, Purchased Gas and Resource Incentive Adjustment Clauses

PSCo has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates.  At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows:

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 will increase to 130 percent of the current goals and incentives will be awarded as one installment in the year following plan achievements.  PSCo will also be able to earn an incentive on 11 percent of net economic benefits at an achievement level of 130 percent and a maximum annual incentive of $30 million.

The CPUC approved the PSCo electric DSM budget of $77.3 million and gas DSM budget of $12.2 million effective Jan. 1, 2012.  This is in addition to $29.4 million for electricity demand response programs recovered through the DSMCA.  Energy efficiency and demand response related DSM costs are recovered through a combination of the DSMCA riders and base rates.  The 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 beginning in 2011 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 the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

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In June 2011, PSCo filed an application with the CPUC for permanent treatment of RECs that are bundled with energy into California.  The application is seeking margin sharing of 30 percent to PSCo and 70 percent to customers for deliveries outside of California and 40 percent to PSCo and 60 percent to customers for deliveries inside of California.  PSCo also proposed that sales of RECs bundled with on-system energy be aggregated with other trading margins and shared 20 percent to PSCo and 80 percent to customers.  In September 2011, the CPUC Staff, the OCC, and the Colorado Energy Consumers filed answer testimony requesting the CPUC approve margin sharing of 8 percent to 25 percent to PSCo for deliveries outside of California and 8 percent to 35 percent for deliveries inside of California.

In January 2012, the CPUC approved the 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.  All customer margin sharing and unspent carbon offset funds will be credited to the RESA regulatory asset balance.  Because the sharing percentage was less than recommended by the CPUC Staff, OCC, and the Colorado Energy Consumers, PSCo plans to file an Application for Rehearing, Reargrument and Reconsideration during the first quarter of 2012.

12.   Commitments and Contingent Liabilities

Commitments

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

CACJA — The CACJA aims to reduce annual emissions of NOxby at least 70 to 80 percent or greater from 2008 levels by 2017 from the coal fired generation identified in the plan.

Fuel Contracts— PSCo has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements.  These contracts expire in various years between 2012 and 2060.  In addition, PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.  PSCo’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2011, were as follows:

(Millions of Dollars)	Dec. 31, 2011
Coal	$	1,458
Natural gas supply		1,067
Natural gas storage & transportation		1,594

Purchased Power Agreements — PSCo has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

PSCo has various pay-for-performance contracts with expiration dates through 2027.  In general, these contracts provide for energy payments based on actual power taken under the contracts, as well as capacity payments.  Capacity 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; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

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Included in electric fuel and purchased power expenses for purchased power agreements were payments for capacity of $178.8 million, $275.4 million and $307.7 million in 2011, 2010 and 2009, respectively.  At Dec. 31, 2011, the estimated future payments for capacity that PSCo is obligated to purchase, subject to availability, were as follows:

(Millions of Dollars)
2012	$	132.0
2013		80.7
2014		75.7
2015		75.9
2016		51.3
2017 and thereafter		77.8
Total	$	493.4

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.

Purchased Power Agreements — Under certain purchased power agreements, PSCo purchases power from independent power producing entities that own natural gas fueled power plants for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases.  These specific purchased power agreements 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 purchased power agreements.

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 1,882 MW and 2,010 MW of capacity under long-term purchased power agreements as of Dec. 31, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities.  These agreements have expiration dates through the year 2028.

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 the capital leases are recorded at the lower of fair-market value or the present value of future lease payments and are amortized over their actual contract term.

WYCO was formed as a joint venture between Xcel Energy and CIG to develop and lease natural gas pipeline, storage, and compression facilities.  Xcel Energy has a 50 percent ownership interest in WYCO.  WYCO leases the facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under a service arrangement.

PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease.  As a result, PSCo had $152.7 million and $149.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2011 and 2010, respectively.

PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income.  Total amortization expenses under capital lease assets were approximately $3.2 million, $5.3 million, and $3.5 million for 2011, 2010 and 2009, respectively.  Following is a summary of property held under capital leases:

(Millions of Dollars)	Dec. 31, 2011			Dec. 31, 2010
Storage, leaseholds and rights	$	200.5		$	196.1
Gas pipeline		20.7			20.7
Property held under capital lease		221.2			216.8
Accumulated depreciation		(29.8	)		(26.6	)
Total property held under capital leases, net	$	191.4		$	190.2

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The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment are accounted for as operating leases.  Total expenses under operating lease obligations were approximately $71.3 million, $70.5 million and $80.9 million for 2011, 2010 and 2009, respectively.  These expenses include payments for capacity recorded to electric fuel and purchased power expenses for purchased power agreements accounted for as operating leases of $47.9 million, $53.8 million and $64.8 million in 2011, 2010 and 2009, respectively.

Included in the future commitments under operating leases are estimated future payments under purchased power agreements 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)	Other Operating Leases		Purchased Power Agreement Operating Leases (a) (b)		Total Operating Leases		Capital Leases
2012	$	14.5	$	55.8	$	70.3	$	30.9
2013		14.1		73.2		87.3		30.8
2014		14.4		79.3		93.7		30.7
2015		14.1		79.8		93.9		30.7
2016		11.0		70.8		81.8		29.4
Thereafter		52.1		607.1		659.2		576.4
Total minimum obligation								728.9
Interest component of obligation								(537.5	)
Present value of minimum obligation							$	191.4

(a) Amounts do not include purchased power agreements accounted for as other commitments, which are recorded to O&M as executed.

(b) Purchased power agreement operating leases contractually expire through 2028.

Guarantees and Indemnifications

In connection with the acquisition of 900 MW of gas-fired generation from subsidiaries of Calpine Development Holdings Inc., PSCo agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  The aggregate liability for PSCo pursuant to these indemnities is not subject to a capped dollar amount. The indemnification obligation expires in December 2012.  PSCo has not recorded a liability related to this indemnity and it has no assets held as collateral related to this agreement at Dec. 31, 2011.

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 — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and other comparable federal and state environmental laws impose liability, without regard to the legality of the original conduct, on certain classes of persons 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 2 sites, where former MGP activities have or may have resulted in actual 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 ultimate remediation that may be conducted.  PSCo anticipates that the majority of the remediation at these sites will continue through at least 2014.  For these sites, PSCo had accrued $0.5 million at Dec. 31, 2011 and Dec. 31, 2010, respectively.  There may be insurance recovery and/or recovery from other PRPs that will offset any costs actually incurred at these sites.  PSCo anticipates that any amounts actually spent will be fully recovered from customers.

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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.  See additional discussion of AROs below.  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.

Other Environmental Requirements

EPA GHG Regulation — In December 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare.  In January 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.  PSCo is unable to determine what the cost of compliance with these new EPA requirements will be as it is not clear whether these requirements will apply to futures changes at PSCo’s power plants.

GHG New Source Performance Standard Proposal — The EPA plans to propose GHG regulations applicable to emissions from new and existing power plants under the CAA.  The EPA had planned to release its proposal in September 2011, but has delayed it without establishing a new proposal date.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — In December 2011, the EPA issued the final EGU MATS rule to replace the proposed EGU MACT rule.  The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and will require coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years.  PSCo believes these costs would be recoverable through regulatory mechanisms and it does not expect a material impact on its results of operations, financial position or cash flows.

Colorado Mercury Regulation — Colorado’s mercury regulations require mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by the end of 2011.  The cost for the Pawnee Generating Station mercury controls was $1.1 million for capital costs with an annual estimate of $0.5 million for sorbent expense.  PSCo has evaluated the Colorado mercury control requirements for its other units in Colorado and believes that, under the current regulations, no further controls will be required other than the planned controls at the Pawnee Generating Station, which are included in the CACJA compliance plan.

Colorado Proposed Surface Impoundment Regulations (Section 9) — In February 2012, the Colorado Department of Public Health and the Environment promulgated new solid waste regulations that establish new design and operating requirements for surface impoundments, including coal ash ponds and cooling tower ponds.  The regulations provide a partial exemption on design upgrades for coal ash ponds pending a final Coal Combustion Residuals Rule from the EPA.  The final rule also exempts PSCo’s ponds that will be closed under the CACJA.  The effective date will be March 30, 2012.  Estimated costs for compliance are approximately $18 million in total through 2018.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S.  PSCo generating facilities will be subject to BART requirements.  Individual states are required to identify the facilities located in their states that will have to reduce SO2, NOx and particulate matter emissions under BART and then set emissions limits for those facilities.

In 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal.  In January 2011, the Colorado Air Quality Control Commission approved a revised Regional Haze BART SIP incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements.  The Colorado SIP is currently pending before the EPA.  PSCo expects the cost of any required capital investment will be recoverable from customers through the CACJA plan recovery mechanisms or other regulatory mechanisms.  Emissions controls are expected to be installed between 2012 and 2017.  The costs associated with the CACJA plan are discussed in Capital Commitments.

In March 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.  Four PSCo plants are named in the petition:  Cherokee, Hayden, Pawnee and Valmont.  The groups allege that 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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Federal Clean Water Act (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 April 2011, the EPA published the proposed rule that sets prescriptive standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office.  PSCo provided comments to the proposed rule, which is expected to be finalized in late 2012.  Due to the uncertainty of the final regulatory requirements, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

Proposed Coal Ash Regulation — PSCo’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste.  In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste.  Coal ash is currently exempt from hazardous waste regulation.  If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, PSCo’s costs associated with the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted.  The EPA has not announced a planned date for a final rule.  The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

PSCo 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 specifically alleges that various maintenance, repair and replacement projects undertaken 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 steam production, electric transmission and distribution and natural gas distribution.  The steam production obligation includes asbestos, ash-containment facilities and radiation sources.  This asbestos abatement removal obligation originated in 1973 with the Clean Air Act, 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 were the in-service date of the various facilities.  Additional AROs have been recorded for steam production plant related to radiation sources in equipment used to monitor the flow of coal, lime and other materials through feeders.

PSCo recognized an ARO for the retirement costs of its natural gas mains and 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.  These electric and natural gas 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 the beginning and ending aggregate carrying amounts of PSCo’s AROs is shown in the table below for the years ended Dec. 31, 2011 and 2010, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2011		Liabilities Recognized		Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2011 (a)
Electric plant
Steam production asbestos	$	63,631	$	-	$	4,163	$	(44,732	)	$	23,062
Steam production ash containment		6,528		-		390		2,531			9,449
Steam production radiation sources		127		-		9		(40	)		96
Electric transmission and distribution		1,746		-		85		7,072			8,903
Natural gas plant
Gas transmission and distribution		655		-		42		-			697
Total liability	$	72,687	$	-	$	4,689	$	(35,169	)	$	42,207

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(Thousands of Dollars)	Beginning Balance Jan. 1, 2010		Liabilities Recognized		Accretion		Revisions to Prior Estimates		Ending Balance Dec. 31, 2010 (a)
Electric plant
Steam production asbestos	$	59,724	$	-	$	3,907	$	-	$	63,631
Steam production ash containment		4,587		32		272		1,637		6,528
Steam production radiation sources		118		-		8		1		127
Electric transmission and distribution		115		-		7		1,624		1,746
Natural gas plant
Gas transmission and distribution		616		-		39		-		655
Total liability	$	65,160	$	32	$	4,233	$	3,262	$	72,687

(a) There were no ARO liabilities settled during the 12 months ended Dec. 31, 2011 or Dec. 31, 2010.

In 2011 and 2010, PSCo revised asbestos, ash containment facilities, radiation sources and electric transmission and distribution AROs due to new estimates and end of life dates.

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 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, 2011 and Dec. 31, 2010 were $380 million and $385 million, respectively.

Legal Contingencies

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material effect on PSCo’s financial position and results of operations.

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against the following utilities, including Xcel Energy Inc., the parent company of PSCo, to force reductions in CO2 emissions:  American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority.  The lawsuits alleged that CO2 emitted by each company is a public nuisance and asked the court to order each utility to cap and reduce its CO2 emissions.  The lawsuits did not demand monetary damages.  In December 2011, the U.S. District Court entered an order dismissing this lawsuit, bringing a close to this litigation.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy Inc., the parent company of PSCo, and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit.  In November 2011, oral arguments were presented.  It is unknown when the Ninth Circuit will render a final opinion.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina.  Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on PSCo’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

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Comer vs. Xcel Energy Inc. et al. — On May 27, 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi.  The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and have filed a motion to dismiss the lawsuit.  It is uncertain when the court will rule on this motion.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on PSCo’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Stone & Webster, Inc. vs. PSCo — In July 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal-fired plant.  Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleged, among other things, that PSCo mismanaged the construction of Comanche Unit 3.  Shaw further claimed that this alleged mismanagement caused delays and damages.  The complaint also alleged that Xcel Energy Inc. and related entities guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement.  In total, Shaw sought approximately $144 million in damages.

In August 2009, PSCo filed an answer and counterclaim denying the allegations in the complaint and alleging that Shaw failed to discharge its contractual obligations and caused delays, and that PSCo is entitled to liquidated damages and excess costs incurred of approximately $82 million.

Following a November 2010 jury trial and subsequent appeal, in November 2011, a confidential settlement was reached dismissing all actions.  This settlement did not have a material effect on PSCo’s consolidated results of operations, cash flows or financial position.

Connie DeWeese vs. PSCo — In November 2008, there was an explosion in Pueblo, Colo., which destroyed a tavern and a neighboring store.  The explosion killed one person and injured seven people.  The Pueblo Fire Department and the Federal Bureau of Alcohol, Tobacco and Firearms have determined a natural gas leak from a pipeline under the street led to the explosion. Beginning in February 2010, four lawsuits were filed in Colorado District Court in Pueblo, Colo. against, among others, PSCo for damages related to personal injuries, property damages and an alleged wrongful death.  PSCo denied and continues to deny liability for this accident.  All but one of the lawsuits have been settled.  The remaining lawsuit, Vigil vs. Xcel Energy Inc., seeks damages for personal injuries and property loss.  As the damages sought are indeterminate and given the uncertainty surrounding the circumstances of this case, PSCo is unable to estimate the range or amount of possible damages.  This matter has been set for trial commencing Sept. 25, 2012.  Neither the settlements nor the damages claimed in the Vigil lawsuit, if recovered, have had or are expected to have a material effect on PSCo’s consolidated results of operations, cash flows or financial position.  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 and liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2011 and Dec. 31, 2010 were:

	See		Remaining
(Thousands of Dollars)	Note(s)		Amortization Period	Dec. 31, 2011				Dec. 31, 2010
Regulatory Assets				Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)		8	Various	$	62,014	$	485,265	$	44,917	$	551,505
Recoverable deferred taxeson AFUDC recorded in plant (b)		1	Plant lives		-		93,410		-		92,444
Contract valuation adjustments (c)		10	Term of related contract		57,595		23,807		43,368		26,498
Depreciation differences (b)		1	One to seven years		4,150		54,892		5,859		12,379
Net AROs (d)		1, 12	Plant lives		-		52,444		-		43,227
Conservation programs (e)		1, 11	One to six years		13,686		24,480		7,770		30,464
Gas pipeline inspection costs			One to five years		13,779		19,689		2,000		25,082
Renewable resources and environmental initiatives		12	One to three years		30,242		4,500		47,961		4,500
Purchased power contract costs		12	Term of related contract		-		23,566		-		18,549
Losses on reacquired debt		4	Term of related debt		1,917		12,833		1,912		14,750
Recoverable purchased natural gas and electric energy costs		1	Less than one year		9,436		-		18,622		-
Other			Various		3,492		14,125		4,187		4,807
Total regulatory assets				$	196,311	$	809,011	$	176,596	$	824,205

Regulatory Liabilities
Plant removal costs	1, 12	Plant lives	$	-	$	380,036	$	-	$	384,640
Deferred electric, gas and steam production costs	7, 1	Less than one year		52,310		-		44,921		-
Investment tax credit deferrals	7, 1	Various		-		27,384		-		29,014
Deferred income tax adjustment	1	Various		-		21,548		-		20,938
Conservation programs (e)	1, 11	Less than one year		8,295		-		-		-
Renewable resources and environmental initiatives	11, 12	Various		-		8,525		-		-
Low income discount program		One to two years		6,068		347		4,706		4,032
Gain from asset sales		One to three years		881		5,467		-		6,700
REC margin sharing (f)	1			-		-		-		26,104
Other		One to five years		1,255		1,135		391		1,418
Total regulatory liabilities			$	68,809	$	444,442	$	50,018	$	472,846

(a) Includes $3.9 million and $7.8 million of unamortized prior service costs at Dec. 31, 2011 and Dec. 31, 2010, respectively.  These amounts are offset by $4.4 and $4.5 million of regulatory assets related to the non-qualified pension plan at Dec. 31, 2011 and Dec. 31, 2010, respectively of which $0.4 million is included in the current asset at Dec. 31, 2011 and Dec. 31, 2010.

(b) Earns a return on investment in the ratemaking process.  These amounts are amortized consistent with recovery in rates.

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

(d) Includes amounts recorded for future recovery of AROs.

(e) Includes over- or under-recovered costs for DSM and conservation programs as well as incentives allowed in certain jurisdictions.

(f) As described in Note 11, in 2011 the CPUC determined that the customers’ share of REC margins will be netted against the RESA regulatory asset balance.  This is reflected in the Dec. 31, 2011 regulatory asset balance.

14.   Segments and Related Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by the chief operating decision maker to evaluate the dual performance of PSCo.  PSCo’s performance is evaluated 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.

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Given the similarity of its regulated electric and regulated natural gas utility operations, PSCo has the following reportable segments:  regulated electric, regulated natural gas and all other.

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

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

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

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

To report income from continuing 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
2011
Operating revenues from external customers	$	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

2010
Operating revenues from external customers	$	3,055,045	$	1,075,446	$	33,879		$	-		$	4,164,370
Intersegment revenues		236		154		-			(390	)		-
Total revenues	$	3,055,281	$	1,075,600	$	33,879		$	(390	)	$	4,164,370
Depreciation and amortization	$	226,374	$	53,535	$	4,230		$	-		$	284,139
Interest charges and financing costs		133,518		29,623		3,497			-			166,638
Income tax expense (benefit)		198,139		36,278		(5,236	)		-			229,181
Net income		299,148		70,279		30,293			-			399,720

2009
Operating revenues from external customers	$	2,678,578	$	1,093,959	$	35,772		$	-		$	3,808,309
Intersegment revenues		266		79		-			(345	)		-
Total revenues	$	2,678,844	$	1,094,038	$	35,772		$	(345	)	$	3,808,309
Depreciation and amortization	$	200,776	$	50,795	$	4,491		$	-		$	256,062
Interest charges and financing costs		121,434		25,242		1,084			-			147,760
Income tax expense (benefit)		123,047		57,375		(10,017	)		-			170,405
Net income		242,265		67,288		13,767			-			323,320

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15.   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)	2011		2010		2009
Operating revenues:
Electric	$	10,896	$	9,428	$	7,751
Other		4,441		3,331		4,441
Operating expenses:
Purchased power		7,187		6,805		5,976
Other operating expenses — paid to Xcel Energy Services Inc.		338,889		307,136		295,934
Interest expense		112		104		586

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

	2011						2010
(Thousands of Dollars)	Accounts Receivable			Accounts Payable			Accounts Receivable			Accounts Payable
NSP-Minnesota		$	11,623		$	-		$	6,674		$	-
NSP-Wisconsin			112			-			164			-
SPS			319			-			2,606			-
Other subsidiaries of Xcel Energy Inc.			9			48,371			11,598			28,270
		$	12,063		$	48,371		$	21,042		$	28,270

16.  Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2011			June 30, 2011			Sept. 30, 2011			Dec. 31, 2011
Operating revenues		$	1,144,447		$	933,100		$	1,063,934		$	1,099,321
Operating income			195,308			153,176			266,422			179,026
Net income			96,630			71,018			140,718			88,437

	Quarter Ended
(Thousands of Dollars)	March 31, 2010			June 30, 2010			Sept. 30, 2010			Dec. 31, 2010
Operating revenues		$	1,202,697		$	947,296		$	954,970		$	1,059,407
Operating income			201,078			156,677			243,055			154,242
Net income			84,250			77,685			158,091			79,694

17.  Acquisition of Generation Assets

In December 2010, PSCo purchased Blue Spruce Energy Center and Rocky Mountain Energy Center from Calpine Development Holdings, Inc. and Riverside Energy Center LLC for $739.0 million plus an additional $3.0 million for working capital adjustments.  The working capital adjustments consisted of the settlement of PSCo’s most recent purchases of energy and capacity under terminated purchased power agreements, adjusted for accrued operating liabilities of the acquired plants of $6.5 million.

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The Blue Spruce Energy Center is a 310 MW simple cycle natural gas-fired power plant that began commercial operations in 2003.  The Rocky Mountain Energy Center is a 652 MW combined-cycle natural gas-fired power plant that began commercial operations in 2004.  Both power plants previously provided energy and capacity to PSCo under purchased power agreements, which were set to expire in 2013 and 2014, respectively.  The acquisition developed out of PSCo's resource planning activities, in which customers' future energy needs are addressed in a formal planning process for meeting PSCo's generation obligations, considering various assumptions and objectives including prices, reliability, and emissions levels.  The generation assets were offered to PSCo as a competitive bid in the resource planning process, and the offer was the least cost option for thermal generation resources.

The purchase price has been allocated as follows based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, including working capital adjustments of approximately $0.2 million recorded in 2011 which were identified through examination of the plants’ books and records:

(Thousands of Dollars)
Assets acquired
Inventory	$	3,791
Property, plant and equipment		735,959
Total assets acquired		739,750
Liabilities assumed
Accrued expenses		7,437
Total liabilities assumed		7,437
Net assets acquired	$	732,313

Operating results for the plants subsequent to the date of acquisition are included in the consolidated statements of income for the year ended Dec. 31, 2010 and Dec 31, 2011.

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 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, 2011, 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 Controls 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, 2011 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 2012 Annual Meeting of Shareholders, which is incorporated by reference.

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, 2011.

Report of Independent Registered Public Accounting Firm — Financial Statements

Consolidated Statements of Income — For the three years ended Dec. 31, 2011, 2010 and 2009.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2011, 2010 and 2009.

Consolidated Balance Sheets — As of Dec. 31, 2011 and 2010.

2. Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2011, 2010 and 2009.

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.
	§	Furnished, herewith, not filed.  Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
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 dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).

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4.01*	Indenture, dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
4.02*	Indentures supplemental to Indenture dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee,:

Dated as of	Previous Filing: Form; Date or file no.	Exhibit No.
Nov. 1, 1993	S-3, (33-51167)	4(b)(2)
Jan. 1, 1994	10-K, 1993	4(b)(3)
Sept. 2, 1994	8-K, September 1994	4(b)
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 number 001-3280).
4.05*	Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust NA, as successor Trustee (Exhibit 4.01 to PSCo Form 8-K (file no 001-3280) dated Aug. 14, 2007).
4.06*	Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U.S. Bank Trust NA, 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 NA, 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 Trust NA, 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 NA, 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)).
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).
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)).

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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).
10.18*+	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).
10.19*	Credit Agreement, dated as of March 17, 2011 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 Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.03 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011).
10.20*	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).
10.21+	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).
10.22+	Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
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, 2011 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Cash Flow, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Stockholder’s Equity and Comprehensive Income, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.

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SCHEDULE II

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2011, 2010 AND 2009

(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:
2011		$	24,054		$	20,371		$	7,423		$	27,150		$	24,698
2010			24,149			21,571			7,192			28,858			24,054
2009			29,195			21,189			14,364			40,599			24,149

(a) Recovery of amounts previously written off.

(b) Principally bad debts written off or transferred.

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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

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

Feb. 27, 2012

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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