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:  001-03789

SOUTHWESTERN PUBLIC SERVICE COMPANY

(Exact name of registrant as specified in its charter)

New Mexico	75-0575400
State or other jurisdiction of incorporation or organization	(I.R.S. Employer Identification No.)

Tyler at Sixth, Amarillo, Texas  79101

(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.  o Yes x 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 Website, 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).  S 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 o Accelerated filer x Non-accelerated filer (Do not check if a smaller reporting company) o Smaller Reporting Company

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

As of Feb. 27, 2012, 100 shares of common stock, par value $1 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.

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

TABLE OF CONTENTS

Index

PART I	3
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	7
Fuel Sources	7
Renewable Energy Sources	8
Wholesale Commodity Marketing Operations	8
Summary of Recent Federal Regulatory Developments	8
Electric Operating Statistics	10
Natural Gas Facilities Used for Electric Generation	11
ENVIRONMENTAL MATTERS	11
EMPLOYEES	12
Item 1A — Risk Factors	12
Item 1B — Unresolved Staff Comments	19
Item 2 — Properties	19
Item 3 — Legal Proceedings	19
Item 4 — Mine Safety Disclosures	19
PART II	20
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6 — Selected Financial Data	20
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	23
Item 8 — Financial Statements and Supplementary Data	23
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58
Item 9A — Controls and Procedures	58
Item 9B — Other Information	58
PART III	58
Item 10 — Directors, Executive Officers and Corporate Governance	58
Item 11 — Executive Compensation	58
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	58
Item 13 — Certain Relationships and Related Transactions, and Director Independence	58
Item 14 — Principal Accountant Fees and Services	58
PART IV	59
Item 15 — Exhibits, Financial Statement Schedules	59
SIGNATURES	62

This Form 10-K is filed by Southwestern Public Service Company (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc.  Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).  This report should be read in its entirety.

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PART 1

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
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy	Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
EIB	New Mexico Environmental Improvement Board
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
NERC	North American Electric Reliability Council
NMED	New Mexico Environment Department
NMPRC	New Mexico Public Regulation Commission
PUCT	Public Utility Commission of Texas
SEC	Securities and Exchange Commission
Electric and Resource Adjustment Clauses
DSM	Demand side management
EECRF	Energy efficiency cost recovery factor
FPPCAC	Fuel and purchased power cost adjustment clause
OATT	Open access transmission tariff
PCRF	Power cost recovery factor
TCRF	Transmission cost recovery factor
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
APBO	Accumulated postretirement benefit obligation
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
BART	Best available retrofit technology
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CCN	Certificate of convenience and necessity
CIPS	Critical Infrastructure Protection Standards
CO2	Carbon dioxide
Codification	FASB Accounting Standards Codification
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
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
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

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NTC	Notifications to construct
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PJM	PJM Interconnection, L.L.C.
PPA	Purchased power agreement
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
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services
WTMPA	West Texas Municipal Power Agency

Measurements
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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COMPANY OVERVIEW

SPS was incorporated in 1921 under the laws of New Mexico.  SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution, and sale of electricity in portions of Texas and New Mexico.  The wholesale customers served by SPS comprised approximately 38 percent of its total KWh sold in 2011.  SPS provides electric utility service to approximately 376,000 retail customers in Texas and New Mexico.  Approximately 74 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2011.  Although SPS’ large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large commercial and industrial electric sales include customers in the oil and gas extraction industry.  For small commercial and industrial customers, significant electric retail sales include customers in the following industries: oil and gas extraction and crop related agricultural industries.  Generally, SPS’ earnings contribute approximately 5 percent to 15 percent of Xcel Energy’s consolidated net income.

SPS’ 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.  SPS 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 SPS and is designed to meet customer and policy maker expectations while creating shareholder value.

Seasonality

The demand for electric power generation is affected by seasonal differences in the weather.  In general, peak sales of electricity occur in the summer and winter months.  As a result, the overall operating results may fluctuate substantially on a seasonal basis.  Additionally, SPS’ 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

SPS’ 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, SPS 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.  While facing these challenges, SPS’ rates are competitive with currently available alternatives.

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states.  The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities.  Each municipality can deny SPS’ rate increase.  SPS can then appeal municipal rate decisions to the PUCT, which hears all municipal rate denials in one hearing.  The NMPRC also has jurisdiction over the issuance of securities.  SPS is regulated by the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.  SPS has received authorization from the FERC to make wholesale electric sales at market-based prices.  See Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules for further discussion.

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

·   FPPCAC — The FPPCAC adjusts monthly to recover the difference between the actual fuel and purchased power costs and the amount included in base rates of SPS’ New Mexico retail jurisdiction.

·   EECRF  — The EECRF rider recovers costs associated with providing energy efficiency programs in Texas.

·   TCRF — The TCRF rider recovers transmission infrastructure improvement costs and changes in wholesale transmission charges.  Effective February 2011, the recovery of the costs associated with the TCRF rider were included in base rates and the TCRF rider was set to zero dollars.

·   PCRF — The PCRF rider allows recovery of certain purchased power costs.  Effective February 2011, the recovery of the costs associated with the PCRF rider are included in base rates, and the PCRF rider was eliminated.

Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric tariff.  Based on regulatory approval in 2011, SO2 and NOx allowance revenues and costs are also recovered through the fixed fuel and purchased energy recovery factor.  The regulations allow retail fuel factors to change up to three times per year.

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The fixed fuel and purchased energy recovery factor provides for accounting of over- or under-recovery of fuel and purchased energy expenses.  Regulations also require refunding or surcharging over- or under-recovery amounts, including interest, when they exceed four percent of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.  In the fourth quarter of 2011, a fuel surcharge was implemented in Texas for recovery of the under-recovered fuel and purchased energy costs and interest.  The surcharge will remain in place until October 2012.

PUCT regulations require periodic examination of SPS’ fuel and purchased energy costs, the efficient use of fuel and purchased energy, the fuel acquisition and management policies and the purchased energy commitments.  SPS is required to file an application for the PUCT to retrospectively review fuel and purchased energy costs at least every three years.

NMPRC regulations require SPS to periodically request authority to continue using its FPPCAC.  The NMPRC reviews SPS’ use of its FPPCAC since the filing of its previous fuel clause continuation filing.  As a follow-up to an SPS rate case, the NMPRC conducted an audit of SPS’ fuel and purchased power costs for a 12-month period from July 2009 through July 2010 and the tracking mechanism to capture costs and revenues associated with SPS’ RECs from assorted wind projects for that period.  In December 2011, the NMPRC authorized SPS to continue its use of its FPPCAC and approved the prudency of the use of the FPPCAC for the period through Dec. 31, 2010.

SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased economic energy cost adjustment clause accepted for filing by the FERC.

Capacity and Demand

Uninterrupted system peak demand for SPS 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
	5,038		4,985		5,210		5,155

The peak demand for the SPS system typically occurs in the summer.  The 2011 uninterrupted system peak demand for SPS occurred on Aug. 2, 2011.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, power purchases and DSM options to meet its net dependable system capacity requirements.

Purchased Power — SPS 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.  SPS 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 — SPS has contractual arrangements with SPP and regional transmission service providers, including PSCo, to deliver power and energy to its native load customers, which are retail and wholesale load obligations with terms of more than one year.

SPS Transmission NTC —In 2010, SPP approved the first of a series of new transmission lines in several states, including Texas, New Mexico and Oklahoma, to help improve electric reliability, strengthen the existing transmission grid and provide outlets for additional renewable wind generation.  As a member of SPP, SPS accepts NTCs for SPP identified lines.  SPS has accepted NTCs for approximately 119 miles of transmission lines at an estimated cost of $126 million.  Under its jurisdiction, the PUCT has thus far approved the construction of two 115 KV electric transmission lines and one 230 KV electric transmission line as part of the project at an estimated cost of $29.1 million.  These approved transmission lines are expected to be completed in the first half of 2013.

TUCO to Woodward District Extra High Voltage Interchange — In June 2009, SPP directed SPS to construct a 178 mile 345 kV transmission line between Lubbock, Texas and Woodward, Okla.  The estimated investment in the new line is $184 million and will be recovered from SPP members, including SPS, in accordance with the SPP OATT and the retail ratemaking process.  In March 2011, SPS filed a CCN to build the line with the PUCT.  A decision is expected in the first quarter of 2012.

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Jones CCN — In August 2011, the PUCT approved SPS’ request for a CCN to build a gas-fired combustion turbine generating unit at SPS’ existing Jones Station in Lubbock, Texas (Jones Unit 4).  This generating unit will add 168 MW of capacity to the SPS service territory.  In February 2012, the NMPRC approved the CCN.

CSAPR — CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S.  CSAPR is discussed further at Note 11 to the financial statements - Environmental Contingencies.  SPS is in the process of determining various scenarios to respond to the CSAPR depending on whether the CSAPR is upheld, reversed, or modified.

If the CSAPR is upheld and unmodified, SPS believes that the CSAPR could ultimately require the installation of additional emission controls on some of SPS’ coal-fired electric generating units.  If compliance is required in a short time frame, SPS may be required to redispatch its system to reduce coal plant operating hours, in order to decrease emissions from its facilities prior to the installation of emission controls.  The expected cost for these scenarios vary significantly and SPS has estimated capital expenditures of approximately $470 million over the next four years for the CSAPR.

SPS Resource Plans — SPS is required to develop and implement a renewable portfolio plan in which ten percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2011, increasing to 15 percent in 2015.  SPS primarily fulfills its renewable portfolio requirements through the purchase of wind energy.  In 2009, the NMPRC granted SPS a variance to allow SPS to delay meeting its solar energy requirement until 2012 provided that SPS compensates for any shortfall of the 2011 solar energy requirement during 2012 through 2014.  SPS executed and received NMPRC approval for a total of 50 MW of PV solar energy PPAs.  SPS requested and was granted a variance from the NMPRC to extend the time to implement a portion of the diversity requirements to January 2014.  SPS is continuing its efforts to acquire viable biomass generation or make a biogas purchase to meet the diversity portion of its renewable energy portfolio plan in New Mexico.

SPS solicited public participation throughout 2011 in its New Mexico 2012 Integrated Resource Planning (IRP) and anticipates filing the IRP with the NMPRC in July 2012.

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	$	1.89		67	%	$	4.37		33	%	$	2.71
2010		1.84		71			4.59		29			2.64
2009		1.74		73			3.80		27			2.30

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

Fuel Sources

Coal— SPS purchases all of the coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO Inc. (TUCO).  TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements.  TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.  The coal supply contract with TUCO expires in 2016 and 2017 for the Harrington station and Tolk station, respectively.  As of Dec. 31, 2011 and 2010, coal inventories at SPS were approximately 43 and 41 days supply, respectively.  TUCO has coal agreements to supply 96 percent of SPS’ coal requirements in 2012, and a declining percentage of the requirements in subsequent years.  SPS’ 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.

Natural gas— SPS uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers.  Natural gas for SPS’ power plants is procured under contracts to provide an adequate supply of fuel; which typically is purchased with terms of one year or less.  The transportation and storage contracts expire in various years from 2012 to 2033.  All of the natural gas supply contracts have pricing that is tied to various natural gas indices.  Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates. These transportation rates are subject to revision based upon FERC or Railroad Commission of Texas 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.  SPS’ commitments related to gas supply contracts were approximately $24 million and $28 million and commitments related to gas transportation and storage contracts were approximately $242 million and $233 million at Dec. 31, 2011 and Dec. 31, 2010, respectively.

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Renewable Energy Sources

SPS’ renewable energy portfolio includes wind, solar and hydroelectric power from both owned generating facilities and purchased power agreements.Renewable energy comprised 8.2 percent and 7.9 percent of SPS’ total owned and purchased energy for 2011 and 2010, respectively.  Biomass, solar and hydroelectric power comprised approximately 0.4 percent and 0.3 percent of renewable energy for 2011 and 2010, respectively, with the remaining renewable energy provided by wind.  As of Dec. 31, 2011, SPS is in compliance with its renewable portfolio standards, which require generation from renewable resources of approximately 3 percent and 10 percent of Texas and New Mexico electric retail sales, respectively.

SPS acquires its wind energy from long-term purchased power agreements with wind farm owners, primarily in the Texas Panhandle area of Texas and New Mexico. SPS currently has six of these agreements in place, with facilities ranging in size from under 2 MW to 161 MW.  In addition to receiving purchased wind energy under these agreements, SPS also typically receives wind RECs, which are used to meet state renewable resource requirements.  Additionally, SPS is required to purchase another 240 MW of wind energy from qualified generating facilities as defined in the Public Utilities Regulatory Policy Act of 1978.  These purchases are made at the SPP Locational Imbalance Price rather than through long-term purchased power agreements.  The average cost per MWh of wind energy under these contracts was approximately $26 and $27 for 2011 and 2010, respectively. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state specific renewable resource requirements, and the year of contract execution.

Generally, contracts executed in 2011 have benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to expiration of the Production Tax Credits in 2012.  At the end of 2011 and 2010, SPS had nearly 700 MW of wind energy on its system.  Additionally, in late 2010, SPS signed an agreement to purchase the output of the 161 MW Spinning Spur Wind Ranch which is expected to be completed in 2012.   Wind energy comprised 7.8 percent and 7.6 percent of SPS’ total owned and purchased energy for 2011 and 2010, respectively.

SPS also offers customer-focused renewable energy initiatives.  The Windsource® program allows customers in New Mexico to purchase a portion or all of their electricity from renewable sources.  Approximately 1,233 and 1,224 customers purchased 7,005 MWh and 7,162 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 70 PV systems with approximately 5 MW of aggregate capacity and 16 PV systems with less than 1 MW of aggregate capacity have been installed in New Mexico under this program as of Dec. 31, 2011 and Dec. 31, 2010, respectively.  

Wholesale Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, accounting practices and certain other activities of SPS, and enforcement of NERC mandatory electric reliability standards.  State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 10 to the financial statements for discussion of other regulatory matters.

FERC Transmission Planning and Cost Allocation — The FERC has approved the open access transmission planning processes for SPS and the RTO serving SPS, SPP, set forth in tariffs filed in compliance with FERC Order 890.  The FERC has also approved SPP tariffs providing for the partial regional allocation of the cost of new transmission facilities.

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 and cost processes will be subject to additional tariff revisions subsequent to Order 1000 compliance filings due in October 2012.

The impacts of the provisions of Order 1000 regarding transmission planning and cost allocation on SPS are not expected to be significant as SPS already participates in SPP regional planning and cost allocation processes.  SPS is in the process of determining the impacts of the Order 1000 requirements related to future transmission development and ownership.  Irrespective of the new rules, SPS is pursuing several new transmission facility projects.

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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.  Under the guidelines, penalties can range between a minimal amount and $290 million.  The guidelines indicate that the FERC can deviate from the guidelines at its discretion.  The guidelines can apply to any investigation where the FERC Staff has not begun settlement negotiations regarding an alleged violation.

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

Market-Based Rate Rules — SPS was granted market-based rate authority and was reauthorized to sell at market-based rates outside its service territory by the FERC in July 2010.  Presently, Xcel Energy Inc.’s utility subsidiaries may not sell power at market-based rates within the SPS balancing authorities, where they have been found to have market power under the FERC’s applicable analysis.  SPS has cost-based coordination tariffs that it may use to make sales in its balancing authorities.

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.  The report did not constitute a finding by the FERC.  Xcel Energy disagreed with the preliminary report and sought to demonstrate 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 SPS 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.  SPS is a member of the SPP 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.

NERC Compliance Audits and Self-Reports — In 2010 and 2011, SPS filed a self-report with SPP regarding potential violations of certain NERC CIPS.  Based on the issues identified with CIPS compliance, SPS submitted a mitigation plan that provides for a comprehensive review of its CIPS compliance programs.

In July 2011, SPS filed a self-report with SPP regarding a potential violation of a NERC reliability standard.  Mitigation actions associated with this self-report are complete, and the violation is not expected to result in a material penalty.

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 SPS is estimated at $11.4 million.  SPS 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		3,700				3,681				3,539
Large commercial and industrial		9,546				9,499				9,518
Small commercial and industrial		4,778				4,824				4,463
Public authorities and other		615				571				552
Total retail		18,639				18,575				18,072
Sales for resale		11,324				10,674				10,209
Total energy sold		29,963				29,249				28,281
Number of customers at end of period
Residential		296,311				295,671				313,063
Large commercial and industrial		201				188				200
Small commercial and industrial		73,567				73,236				77,017
Public authorities and other		6,177				6,134				6,088
Total retail		376,256				375,229				396,368
Wholesale		27				39				45
Total customers		376,283				375,268				396,413
Electric revenues (Thousands of Dollars)
Residential	$	321,533			$	300,173			$	284,760
Large commercial and industrial		418,388				400,383				383,692
Small commercial and industrial		333,504				333,093				319,608
Public authorities and other		42,973				38,929				34,933
Total retail		1,116,398				1,072,578				1,022,993
Wholesale		511,316				485,068				408,460
Other electric revenues		79,851				55,344				27,770
Total electric revenues	$	1,707,565			$	1,612,990			$	1,459,223
KWh sales per retail customer		49,537				49,503				45,593
Revenue per retail customer	$	2,967			$	2,858			$	2,581
Residential revenue per KWh		8.69	¢			8.15	¢			8.05	¢
Large commercial and industrial revenue per KWh		4.38				4.22				4.03
Small commercial and industrial revenue per KWh		6.98				6.90				7.16
Wholesale revenue per KWh		4.52				4.54				4.00

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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		14,818	48	%	15,486		51	%	15,364		53	%
Natural Gas		13,167	43		12,206		40		11,835		41
Wind (a)		2,386	8		2,295		8		1,848		6
Other (b)		409	1		361		1		128		-
Total		30,780	100	%	30,348		100	%	29,175		100	%
Owned generation		19,310	63	%	19,303		64	%	19,652		67	%
Purchased generation		11,470	37		11,045		36		9,523		33
Total		30,780	100	%	30,348		100	%	29,175		100	%

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

(b) Includes energy from other sources, including nuclear, hydroelectric, solar, biomass, oil and waste.  Distributed generation from the Solar*Rewards program is not included.

Natural Gas Facilities Used for Electric Generation

SPS does not provide natural gas service at retail, but purchases and transports natural gas for certain of its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines.  SPS is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce; and to the jurisdiction of the United States Department of Transportation (DOT) and the PUCT for pipeline safety compliance.

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 SPS cannot predict the ultimate impact the Pipeline Safety Act will have on its costs, operations or financial results, SPS is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.

ENVIRONMENTAL MATTERS

SPS’ 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.  SPS has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.  SPS’ facilities have been designed and constructed to operate in compliance with applicable environmental standards.

SPS 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 SPS’ operations.  See Notes 10 and 11 to the 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, SPS 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 SPS 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, SPS had 1,194 full-time employees, 804 of which are covered under collective bargaining agreements.  See Note 7 to the 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 SPS, 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, SPS 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 SPS’ 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 SPS’ strategy.  The process for risk management and 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 SPS’ 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 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.

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.

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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 state utility commissions regulate 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 and the sale of electric energy 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.

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.

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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 SPP.  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 transactions with affiliates that participate 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.

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 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.

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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.

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.

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 $18.0 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 $64.4 million, $67.1 million and $66.8 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs.  This could adversely affect our liquidity.  The 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.

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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 11 to the 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.

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 emissions of SO2 and NOx,mercury, regional haze, ozone, ash management and cooling water intake systems.  The costs of investment to comply with these rules could be substantial.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased 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.

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a 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 and transmission systems 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, 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.

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.

18

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

Our electric utility business is 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.  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.

Item 2 — Properties

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

Electric Utility Generating Stations:

SPS				Summer 2011
				Net Dependable
Station, Location and Unit	Fuel	Installed		Capability (MW)
Steam:
Harrington-Amarillo, Texas, 3 Units	Coal		1976-1980	1,018
Tolk-Muleshoe, Texas, 2 Units	Coal		1982-1985	1,067
Cunningham-Hobbs, NM, 2 Units	Natural Gas		1957-1965	254
Jones-Lubbock, Texas, 2 Units	Natural Gas		1971-1974	486
Maddox-Hobbs, NM, 1 Unit	Natural Gas		1967	112
Moore County-Amarillo, Texas, 1 Unit	Natural Gas		1954	46
Nichols-Amarillo, Texas, 3 Units	Natural Gas		1960-1968	457
Plant X-Earth, Texas, 4 Units	Natural Gas		1952-1964	412
Combustion Turbine:
Carlsbad-Carlsbad, NM, 1 Unit	Natural Gas		1968	10
Cunningham-Hobbs, NM, 2 Units	Natural Gas		1998	214
Jones-Lubbock, Texas, 1 Unit	Natural Gas		2011	171	(a)
Maddox-Hobbs, NM, 1 Unit	Natural Gas		1963-1976	61
Riverview-Electric City, Texas	Natural Gas		1973	22
		Total		4,330

(a)  Construction of Jones Unit 3 was completed in 2011.

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

Conductor Miles
345 KV	6,806
230 KV	9,705
115 KV	11,216
Less than 115 KV	21,486

SPS had 425 electric utility transmission and distribution substations at Dec. 31, 2011.

Item 3 — Legal Proceedings

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

Additional Information

See Note 11 to the financial statements for further discussion of legal claims and environmental proceedings.  See Item 1 and Note 10 to the financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

Item 4 — Mine Safety Disclosures

None.

19

PART II

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

SPS is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.

SPS has dividend restrictions imposed by FERC rules and state regulatory commissions.

· 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.

· State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent.  In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating.  SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 52.0 percent at Dec. 31, 2011.

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

The dividends declared during 2011 and 2010 were as follows:

(Thousands of Dollars)	2011		2010
First quarter	$	15,861	$	16,896
Second quarter		16,040		16,674
Third quarter		16,143		16,292
Fourth quarter		16,913		16,357

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 SPS 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 the financial condition and results of operations during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the accompanying financial statements and the related notes to the financial statements.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,”  “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; 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; environmental laws and regulations; actions by regulatory bodies; 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 SPS 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.

20

Results of Operations

SPS’ net income was approximately $89.9 million for 2011, compared with net income of approximately $78.1 million for 2010.  The increase is primarily due to higher electric revenues, primarily due to the Texas retail rate increase effective in the first quarter, as well as warmer summer weather, partially offset by higher O&M expenses, depreciation expense and property taxes.

Electric Revenues and Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power.  The design of fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses and, therefore, changes in fuel or purchased power costs can impact earnings.  The following table details the electric revenues and margin:

(Millions of Dollars)	2011			2010
Electric revenues	$	1,708		$	1,613
Electric fuel and purchased power		(1,089	)		(1,024	)
Electric margin	$	619		$	589

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

Electric Revenues

(Millions of Dollars)	2011 vs. 2010
Fuel and purchased power cost recovery	$	41
Transmission revenue		24
Retail rate increases (Texas)		18
Firm wholesale (a)		10
Estimated impact of weather		10
Trading		9
Conservation and DSM revenue (offset by expenses)		4
SPS fuel cost allocation regulatory accruals (b)		(11	)
Retail sales decrease (excluding weather impact) (a)		(8	)
Other, net		(2	)
Total increase in electric revenues	$	95

(a) Firm wholesale and retail sales decrease have not been adjusted for impacts of the sale of SPS electric distribution assets to the city of Lubbock, Texas in October 2010.  As a result of the asset sale, approximately $11.4 million of electric revenues which were previously included in retail sales are now included in firm wholesale.

(b) During the second quarter of 2010, SPS resolved certain fuel cost allocation issues allowing for the release of previously established reserves of approximately $11 million.

21

Electric Margin

(Millions of Dollars)	2011 vs. 2010
Retail rate increases (Texas)	$	18
Transmission revenue, net of costs		10
Estimated impact of weather		10
Firm wholesale (a)		9
Conservation and DSM revenue (offset by expenses)		4
SPS fuel cost allocation regulatory accruals (b)		(11	)
Retail sales decrease (excluding weather impact) (a)		(8	)
Other, net		(2	)
Total increase in base electric margin	$	30

(a) Firm wholesale increase and retail sales decrease have not been adjusted for impacts of the sale of SPS electric distribution assets to the city of Lubbock, Texas in October 2010.  As a result of the asset sale, approximately $11.4 million of electric revenues which were previously included in retail sales are now included in firm wholesale.

(b) During the second quarter of 2010, SPS resolved certain fuel cost allocation issues allowing for the release of previously established reserves of approximately $11 million.

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased $2.8 million, or 1.1 percent, for 2011 compared with 2010.  The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2011 vs. 2010
Higher labor and contract labor costs	$	4
Higher employee benefit expense		3
Amortization of gain on Lubbock sale		(5	)
Other, net		1
Total increase in O&M expenses	$	3

DSM Program Expenses — DSM program expenses increased approximately $3.8 million for 2011 compared with 2010.  The higher expenses are attributable to timing and an increase in the rider rates used to recover the program expenses.  DSM program expenses are generally recovered in major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expenses increased approximately $3.0 million, or 2.9 percent for 2011 compared with 2010.  The increase in depreciation expense is primarily due to Jones Unit 3 going into service in June 2011 and planned system expansion, offset by a decrease in depreciation expense resulting from the sale of Lubbock distribution assets and a decrease in rate case amortization.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased approximately $2.3 million, or 5.6 percent for 2011 compared with 2010.  The increase is primarily due to an increase in property taxes in Texas.

AFUDC — AFUDC increased approximately $1.7 million for 2011 compared with 2010.  This increase was primarily due to higher average construction work in progress due to major construction projects, including Jones Unit 3 and Unit 4, as well as transmission projects.

Interest Charges — Interest charges increased $1.2 million, or 1.9 percent, for 2011 compared with 2010.  The increase was primarily due to higher long-term debt levels, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $6.3 million for 2011 compared with 2010.  The increase in income tax expense was primarily due to an increase in pretax income in 2011.  The effective tax rate was 38.0 percent for 2011, compared with 38.5 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 and a write-off of tax benefit previously recorded for Medicare Part D subsidies.   See Note 6 to the financial statements for further discussion.

22

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, SPS 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 9 to the financial statements for further discussion of market risks associated with derivatives.

Commodity Price Risk — SPS is exposed to commodity price risk in its electric 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.  SPS’ risk management policy allows it to manage commodity price risk to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk — SPS conducts an immaterial amount of short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments.  SPS’ 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.

Interest Rate Risk — SPS is subject to the risk of fluctuating interest rates in the normal course of business.  SPS’ 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, a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would have an immaterial impact to pretax interest expense annually.  See Note 9 to the financial statements for a discussion of SPS’ interest rate derivatives.

Credit Risk — SPS is also exposed to credit risk.  Credit risk relates to the risk of loss resulting from counterparties’ nonperformance of their contractual obligations.  SPS 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 or decrease in prices would have an immaterial impact on credit exposure.

SPS conducts standard credit reviews for all counterparties.  SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.  Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.  Distress in the financial markets could increase SPS’ credit risk.

Item 8 — Financial Statements and Supplementary Data

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

See Note 15 to the financial statements for summarized quarterly financial data.

23

Management Report on Internal Controls Over Financial Reporting

The management of SPS is responsible for establishing and maintaining adequate internal control over financial reporting.  SPS’ internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and SPS’ 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.

SPS management assessed the effectiveness of SPS’ internal 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, SPS’ internal control over financial reporting is effective based on those criteria.

/s/ C. RILEY HILL	/s/ TERESA S. MADDEN
C. Riley Hill	Teresa S. Madden
President, Chief Executive Officer and Director	Senior Vice President, Chief Financial Officer and Director
Feb. 27, 2012	Feb. 27, 2012

24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Southwestern Public Service Company

We have audited the accompanying balance sheets and statements of capitalization of Southwestern Public Service Company (the “Company”) as of December 31, 2011 and 2010, and the related 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 financial statements present fairly, in all material respects, the financial position of Southwestern Public Service Company as of December 31, 2011 and 2010, and the results of its operations and its 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 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

25

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2011			2010			2009
Operating revenues	$	1,707,565		$	1,612,990		$	1,459,223
Operating expenses
Electric fuel and purchased power		1,089,415			1,023,938			914,350
Operating and maintenance expenses		251,886			249,071			221,681
Demand side management program expenses		15,415			11,625			7,270
Depreciation and amortization		106,974			103,935			104,602
Taxes (other than income taxes)		43,278			40,984			38,503
Total operating expenses		1,506,968			1,429,553			1,286,406
Operating income		200,597			183,437			172,817
Other income, net		406			27			264
Allowance for funds used during construction — equity		5,342			4,188			4,082
Interest charges and financing costs
Interest charges — includes other financing costs of $2,964, $2,635 and $2,653, respectively		65,095			63,912			71,688
Allowance for funds used during construction — debt		(3,784	)		(3,193	)		(2,770	)
Total interest charges and financing costs		61,311			60,719			68,918
Income before income taxes		145,034			126,933			108,245
Income taxes		55,133			48,866			40,495
Net income	$	89,901		$	78,067		$	67,750

See Notes to Financial Statements

26

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2011			2010			2009
Operating activities
Net income	$	89,901		$	78,067		$	67,750
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		109,207			106,207			106,897
Demand side management program amortization		1,811			2,034			1,793
Deferred income taxes		55,508			25,312			30,373
Amortization of investment tax credits		(275	)		(341	)		(298	)
Allowance for equity funds used during construction		(5,342	)		(4,188	)		(4,082	)
Provision for bad debts		3,655			3,990			3,765
Net derivative losses (gains)		268			268			(2,698	)
Changes in operating assets and liabilities:
Accounts receivable		(23,518	)		1,691			11,919
Accrued unbilled revenues		6,042			(4,399	)		(7,922	)
Inventories		(5,726	)		(2,702	)		19,935
Prepayments and other		(2,480	)		10,920			(10,558	)
Accounts payable		(1,527	)		(17,015	)		(5,788	)
Net regulatory assets and liabilities		6,090			(20,082	)		43,946
Other current liabilities		5,717			3,902			(3,236	)
Pension and other employee benefit obligations		(7,576	)		(4,213	)		(11,229	)
Change in other noncurrent assets		1,509			(2,868	)		(11,067	)
Change in other noncurrent liabilities		(4,299	)		747			(7,989	)
Net cash provided by operating activities		228,965			177,330			221,511
Investing activities
Utility capital/construction expenditures		(308,223	)		(309,408	)		(211,866	)
Proceeds from the sale of assets		-			87,823			-
Allowance for equity funds used during construction		5,342			4,188			4,082
Investments in utility money pool arrangement		(40,300	)		(204,200	)		(990,800	)
Receipts from utility money pool arrangement		40,300			281,200			1,004,300
Other, net		221			-			-
Net cash used in investing activities		(302,660	)		(140,397	)		(194,284	)
Financing activities
Proceeds (repayment of) from short-term borrowings, net		(49,000	)		49,000			-
Proceeds from issuance of long-term debt		193,137			-			-
Repayment of long-term debt		(101,800	)		(25,000	)		(100,057	)
Borrowings under utility money pool arrangement		293,500			483,200			-
Repayments under utility money pool arrangement		(288,500	)		(483,200	)		-
Capital contributions from parent		89,631			583			16,243
Dividends paid to parent		(64,401	)		(67,101	)		(66,845	)
Net cash provided by (used in) financing activities		72,567			(42,518	)		(150,659	)
Net change in cash and cash equivalents		(1,128	)		(5,585	)		(123,432	)
Cash and cash equivalents at beginning of year		1,778			7,363			130,795
Cash and cash equivalents at end of year	$	650		$	1,778		$	7,363
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(57,122	)	$	(57,969	)	$	(69,619	)
Cash paid for income taxes, net		(2,245	)		(7,277	)		(20,118	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	23,570		$	9,539		$	12,432

See Notes to Financial Statements

27

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

(amounts in thousands of dollars, except share data)

	Dec. 31
	2011			2010
Assets
Current assets
Cash and cash equivalents	$	650		$	1,778
Accounts receivable, net		65,030			44,871
Accounts receivable from affiliates		1,314			1,610
Accrued unbilled revenues		104,142			110,184
Inventories		35,575			29,849
Regulatory assets		25,244			21,547
Derivative instruments		7,892			7,892
Deferred income taxes		18,247			19,051
Prepayments and other		7,486			5,006
Total current assets		265,580			241,788
Property, plant and equipment, net		2,594,732			2,401,266
Other assets
Regulatory assets		294,813			283,207
Derivative instruments		56,841			64,734
Other		11,883			10,668
Total other assets		363,537			358,609
Total assets	$	3,223,849		$	3,001,663
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	-		$	44,500
Short-term debt		-			49,000
Borrowings under utility money pool arrangement		5,000			-
Accounts payable		140,412			134,322
Accounts payable to affiliates		11,828			24,525
Regulatory liabilities		57,104			53,197
Taxes accrued		19,910			19,867
Accrued interest		13,842			12,128
Dividends payable to parent		16,913			16,358
Derivative instruments		3,601			3,601
Other		29,841			21,349
Total current liabilities		298,451			378,847
Deferred credits and other liabilities
Deferred income taxes		596,581			541,204
Deferred investment tax credits		1,776			2,051
Regulatory liabilities		105,335			134,952
Asset retirement obligations		27,266			21,131
Derivative instruments		41,391			44,991
Pension and employee benefit obligations		76,307			52,280
Other		6,569			10,827
Total deferred credits and other liabilities		855,225			807,436
Commitments and contingencies
Capitalization
Long-term debt		993,314			853,267
Common stock – 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2011 and Dec. 31, 2010		-			-
Additional paid in capital		783,162			693,531
Retained earnings		295,201			270,257
Accumulated other comprehensive loss		(1,504	)		(1,675	)
Total common stockholder’s equity		1,076,859			962,113
Total liabilities and equity	$	3,223,849		$	3,001,663

See Notes to Financial Statements

28

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

(amounts in thousands of dollars, except 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	$	-	$	676,705	$	259,159		$	(5,559	)	$	930,305
Net income								67,750						67,750
Net derivative instrument changes during the period, net of tax of $2,093											3,712			3,712
Comprehensive income for 2009														71,462
Common dividends declared to parent								(68,500	)					(68,500	)
Contribution of capital by parent						16,243								16,243
Balance at Dec. 31, 2009		100	$	-	$	692,948	$	258,409		$	(1,847	)	$	949,510
Net income								78,067						78,067
Net derivative instrument changes during the period, net of tax of $96											172			172
Comprehensive income for 2010														78,239
Common dividends declared to parent								(66,219	)					(66,219	)
Contribution of capital by parent						583								583
Balance at Dec. 31, 2010		100	$	-	$	693,531	$	270,257		$	(1,675	)	$	962,113
Net income								89,901						89,901
Net derivative instrument changes during the period, net of tax of $98											171			171
Comprehensive income for 2011														90,072
Common dividends declared to parent								(64,957	)					(64,957	)
Contribution of capital by parent						89,631								89,631
Balance at Dec. 31, 2011		100	$	-	$	783,162	$	295,201		$	(1,504	)	$	1,076,859

See Notes to Financial Statements

29

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars, except share data)

	Dec. 31
	2011			2010
Long-Term Debt
First Mortgage Bonds, Series due:
Aug. 15, 2041, 4.5%	$	200,000		$	-
Unsecured Senior E Notes, due Oct. 1, 2016, 5.6%		200,000			200,000
Unsecured Senior G Notes, due Dec. 1, 2018, 8.75%		250,000			250,000
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6%		100,000			100,000
Unsecured Senior F Notes, due Oct. 1, 2036, 6%		250,000			250,000
Pollution control obligations, securing pollution control revenue bonds, due:
July 1, 2011, 5.2%		-			44,500
Sept. 1, 2016, 5.75%		-			57,300
Unamortized discount		(6,686	)		(4,033	)
Total		993,314			897,767
Less current maturities		-			44,500
Total long-term debt	$	993,314		$	853,267
Common Stockholder’s Equity
Common stock — 200 shares authorized of $1.00 par value, 100 shares outstanding at Dec. 31, 2011 and 2010, respectively	$	-		$	-
Additional paid in capital		783,162			693,531
Retained earnings		295,201			270,257
Accumulated other comprehensive loss		(1,504	)		(1,675	)
Total common stockholder’s equity	$	1,076,859		$	962,113

See Notes to Financial Statements

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NOTES TO FINANCIAL STATEMENTS

1.  Summary of Significant Accounting Policies

Business and System of Accounts— SPS is principally engaged in the regulated generation, purchase, transmission, distribution and sale of electricity.  SPS’ financial statements and disclosures are presented in accordance with GAAP.  All of SPS’ 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.

Variable Interest Entities— SPS evaluates its arrangements and contracts with other entities, including but not limited to, purchased power agreements and fuel contracts to determine if the other party is a variable interest entity and if so, if SPS is the primary beneficiary.  SPS 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 SPS is a variable interest entity’s primary beneficiary.  See Note 11 for further discussion of variable interest entities.

Use of Estimates— In recording transactions and balances resulting from business operations, SPS 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— SPS 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, SPS 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 SPS’ financial condition, results of operations and cash flows in the period the write-offs are recorded.  See Note 12 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.  SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP. The revenues and charges from SPP related to serving retail and wholesale electric customers comprising the native load of SPS are recorded on a net basis within cost of sales. Revenues and charges for short-term wholesale sales of excess energy transacted through SPP are recorded on a gross basis in electric revenues and cost of sales.

SPS has various rate-adjustment mechanisms in place that currently provide for the recovery of electric fuel costs and 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.

Conservation Programs — SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system.  These programs include, but are not limited to commercial process efficiency and lighting updates, and residential rebates for participation in air conditioner interruption and energy-efficient appliances.

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The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs 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.  SPS recovers approved conservation program costs in base rate revenue or through a rider.

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.

SPS 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 2.7 percent for the years ended Dec. 31, 2011 and 2010, and 2.6 percent for the year ended Dec. 31, 2009.

Leases — SPS 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 11 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 SPS’ rate base for establishing utility service rates.

Asset Retirement Obligations — SPS 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.

SPS 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.

Income Taxes— SPS 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.  SPS defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  SPS 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 12.

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SPS 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.  SPS recognizes a tax position in its 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.

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

Xcel Energy Inc. and its subsidiaries, including SPS, 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 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments — SPS uses derivative instruments in connection with its utility commodity price, interest rate, 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 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; and interest rate hedging transactions are recorded as a component of interest expense.

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 — SPS 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.

SPS 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 9 for further discussion of SPS’ 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 statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from SPS are apportioned to NSP-Minnesota and PSCo.  Commodity trading activities are not associated with energy produced from SPS’ 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 9 for further discussion.

Fair Value Measurements — SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its 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, SPS may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.  See Note 9 for further discussion.

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Cash and Cash Equivalents— SPS 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.  SPS 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 are marketable 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, SPS 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 certain state regulatory orders, SPS reduces recoverable fuel costs for the value of certain RECs and 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.

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.  SPS 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 statements of cash flows.

Environmental Costs— Environmental costs are recorded when it is probable SPS 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.

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 SPS’ 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 11 for further discussion of environmental costs.

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

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.  See Note 7 for further discussion of benefit plans and other postretirement benefits.

Guarantees— SPS 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 SPS is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.

Reclassifications — Certain prior year amounts have been reclassified to conform to the current year presentation. Changes in pension and other employee benefit obligations were reclassified as a separate item from changes in other noncurrent liabilities within the statements of cash flows.  These reclassifications did not have an impact on net cash provided by operating activities.

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Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2011 up to the date of issuance of these 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.  SPS does not expect the implementation of this guidance to have a material impact on its 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.  SPS does not expect the implementation of this presentation guidance to have a material impact on its 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 balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual periods.  SPS does not expect the implementation of this disclosure guidance to have a material impact on its financial statements.

3.  Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2011			Dec. 31, 2010
Accounts receivable, net
Accounts receivable	$	70,410		$	49,966
Less allowance for bad debts		(5,380	)		(5,095	)
	$	65,030		$	44,871
Inventories
Materials and supplies	$	17,472		$	15,093
Fuel		18,103			14,756
	$	35,575		$	29,849
Property, plant and equipment, net
Electric plant	$	4,142,389		$	3,826,202
Construction work in progress		153,672			221,025
Total property, plant and equipment		4,296,061			4,047,227
Less accumulated depreciation		(1,701,329	)		(1,645,961	)
	$	2,594,732		$	2,401,266

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4.  Borrowings and Other Financing Instruments

Short-Term Borrowings

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility with a borrowing limit of $300 million, of which there were no borrowings outstanding during the three months ended Dec. 31, 2011.  Commercial paper outstanding for SPS 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	$	300		$	248		$	248
Amount outstanding at period end		-			49			-
Average amount outstanding		54			8			-
Maximum amount outstanding		161			65			-
Weighted average interest rate, computed on a daily basis		0.37	%		0.37	%		N/A
Weighted average interest rate at end of period		N/A			0.37			N/A

Credit Facilities — In order to use its commercial paper program to fulfill short-term funding needs, SPS 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, SPS executed a new four-year credit agreement.  The total size of the credit facility is $300 million and terminates in March 2015. SPS has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

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 SPS’ credit facility include:

·   The credit facility may be increased by up to $50 million.

·   The credit facility has a financial covenant requiring that SPS’ debt-to-total capitalization ratio be less than or equal to 65 percent.  SPS was in compliance as its debt-to-total capitalization ratio was 48 percent at Dec. 31, 2011.  If SPS 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 SPS will be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15 percent of SPS’ 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, SPS had the following committed credit facility available (in millions):

Credit Facility		Drawn		Available
$	300.0	$	-	$	300.0

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  SPS had no direct advances on the credit facility outstanding at Dec. 31, 2011 and 2010.

Letters of Credit — SPS 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 no letters of credit outstanding.

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2011
Borrowing limit	$	100
Amount outstanding at period end		5
Average amount outstanding		1
Maximum amount outstanding		9
Weighted average interest rate, computed on a daily basis		0.35	%
Weighted average interest rate at end of period		0.35
(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	$	100		$	100		$	100
Amount outstanding at period end		5			-			-
Average amount outstanding		12			16			-
Maximum amount outstanding		71			77			-
Weighted average interest rate, computed on a daily basis		0.35	%		0.37	%		N/A
Weighted average interest rate at end of period		0.35			N/A			N/A

Long-Term Borrowings and Other Financing Instruments 

Generally, all real and personal property used in or in connection with the electric utility business of SPS is subject to the liens of its first mortgage indenture.  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, SPS issued $200 million of 4.50 percent first mortgage bonds due Aug. 15, 2041.  During the next five years, SPS has long-term debt maturities of $200 million due in 2016.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $8.9 million and $5.9 million, net of amortization, at Dec. 31, 2011 and 2010, respectively.  SPS is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend Restrictions— SPS’ 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. 

SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent.  In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating.  SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 52.0 percent at Dec. 31, 2011.  

5. Preferred Stock

SPS has authorized the issuance of preferred stock.

Preferred			Preferred
Shares			Shares
Authorized	Par Value		Outstanding
10,000,000	$	1.00	None

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6.  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, SPS became subject to additional taxes and was required to reverse previously recorded tax benefits in the period of enactment.  SPS expensed approximately $1.9 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2011.  SPS does not expect the $1.9 million of additional tax expense to recur in future periods. 

Federal Audit— SPS isa 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 — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.   As of Dec. 31, 2011, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2007.  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	$	0.2	$	0.2
Unrecognized tax benefit - Temporary tax positions		4.6		4.1
Unrecognized tax benefit balance	$	4.8	$	4.3

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	$	4.3		$	2.9		$	3.5
Additions based on tax positions related to the current year		1.5			1.3			1.4
Reductions based on tax positions related to the current year		(0.2	)		-			-
Additions for tax positions of prior years		2.5			0.2			0.8
Reductions for tax positions of prior years		(0.3	)		(0.1	)		(0.1	)
Settlements with taxing authorities		(3.0	)		-			(2.7	)
Balance at Dec. 31	$	4.8		$	4.3		$	2.9

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

(Millions of Dollars)	Dec. 31, 2011			Dec. 31, 2010
NOL and tax credit carryforwards	$	(2.0	)	$	(0.1	)

The increase in the unrecognized tax benefit balance of $0.5 million in 2011 was due to the addition of uncertain tax positions related to current and prior years’ activity, partially offset by a decrease due to the resolution of certain federal audit matters.  SPS’ 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, SPS does not anticipate total unrecognized tax benefits will significantly change within the next 12 months.

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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	$	(0.2	)	$	(0.1	)	$	(0.3	)
Interest income (expense) related to unrecognized tax benefits		0.1			(0.1	)		0.2
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(0.1	)	$	(0.2	)	$	(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	$	175.1	$	5.9
Federal tax credit carryforwards		1.3		1.1
State NOL carryforwards		37.3		17.9
Valuation allowance for state NOL carryforwards		-		(1.3	)

The federal carryforward periods expire between 2021 and 2031.  The state carryforward periods expire between 2012 and 2030.

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		2.7			1.8			2.7
Resolution of income tax audits and other		0.3			0.1			0.2
Tax credit recognized, net of federal income tax expense		(0.3	)		(0.4	)		(0.4	)
Regulatory differences - utility plant items		(0.1	)		0.2			0.2
Change in unrecognized tax benefits		-			-			(0.2)
Previously recognized Medicare Part D subsidies		-			1.5			-
Other, net		0.4			0.3			(0.1	)
Effective income tax rate		38.0	%		38.5	%		37.4	%

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

(Thousands of Dollars)	2011			2010			2009
Current federal tax (benefit) expense	$	(1,993	)	$	19,850		$	6,922
Current state tax expense		3,287			2,669			4,145
Current change in unrecognized tax (benefit) expense		(1,394	)		1,376			(647	)
Deferred federal tax expense		51,111			26,050			29,234
Deferred state tax expense		3,240			747			870
Deferred change in unrecognized tax expense (benefit)		1,365			(1,340	)		438
Deferred tax credits		(208	)		(145	)		(169	)
Deferred investment tax credits		(275	)		(341	)		(298	)
Total income tax expense	$	55,133		$	48,866		$	40,495

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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	$	56,181		$	25,318		$	31,740
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(575	)		90			726
Tax expense allocated to other comprehensive income		(98	)		(96	)		(2,093	)
Deferred tax expense	$	55,508		$	25,312		$	30,373

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

(Thousands of Dollars)	2011		2010
Deferred tax liabilities:
Difference between book and tax bases of property	$	597,122	$	483,998
Employee benefits		56,069		53,505
Other		21,359		20,614
Total deferred tax liabilities	$	674,550	$	558,117
Deferred tax assets:
NOL carryforward	$	65,278	$	4,482
Unbilled revenue - fuel costs		13,138		11,051
Regulatory liabilities		7,501		9,506
Rate refund		2,708		2,248
Deferred fuel costs		2,473		3,668
Bad debts		1,936		1,835
Other		3,182		3,174
Total deferred tax assets	$	96,216	$	35,964
Net deferred tax liability	$	578,334	$	522,153

7. Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to SPS.  Consistent with the process for rate recovery of pension and postretirement benefits for its employees, SPS accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans.  SPS is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, SPS 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 SPS employees.

Xcel Energy, which includes SPS, offers various benefit plans to its employees.  Approximately 67 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements.  At Dec. 31, 2011, SPS had 804 bargaining employees covered under a collective-bargaining agreement, which expires in October 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.

40

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 SPS, 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 SPS’ 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 SPS 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 the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts.  The pension cost determination assumes a forecasted mix of investment types over the long-term.  Investment returns were above the assumed levels of 6.80 in 2011 and 2010 and 8.50 percent in 2009.  Xcel Energy Inc. and SPS continually review pension assumptions.  In 2012, SPS’ estimated investment-return assumption is 6.68 percent.

The assets are invested in a portfolio according to Xcel Energy Inc.’s and SPS’ 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 SPS 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.

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

	2011			2010
Domestic and international equity securities		20	%		15	%
Long-duration fixed income securities		50			61
Short-to-intermediate term fixed income securities		9			5
Alternative investments		18			11
Cash		3			8
Total		100	%		100	%

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

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Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, SPS’ 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	$	13,539	$	-		$	-	$	13,539
Derivatives		-		1,600			-		1,600
Government securities		-		25,233			-		25,233
Corporate bonds		-		112,328			-		112,328
Asset-backed securities		-		-			4,018		4,018
Mortgage-backed securities		-		-			7,907		7,907
Common stock		6,770		-			-		6,770
Private equity investments		-		-			16,159		16,159
Commingled funds		-		165,495			-		165,495
Real estate		-		-			3,586		3,586
Securities lending collateral obligation and other		-		(6,581	)		-		(6,581	)
Total	$	20,309	$	298,075		$	31,670	$	350,054

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	48,854	$	-		$	-	$	48,854
Derivatives		-		610			-		610
Government securities		-		12,576			-		12,576
Corporate bonds		-		111,208			-		111,208
Asset-backed securities		-		-			3,450		3,450
Mortgage-backed securities		-		-			11,060		11,060
Common stock		5,574		-			-		5,574
Private equity investments		-		-			11,464		11,464
Commingled funds		-		130,341			-		130,341
Real estate		-		-			10,132		10,132
Securities lending collateral obligation and other		-		(7,848	)		-		(7,848	)
Total	$	54,428	$	246,887		$	36,106	$	337,421

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

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2011		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2011
Asset-backed securities	$	3,450	$	328		$	(355	)	$	595		$	4,018
Mortgage-backed securities		11,060		170			(865	)		(2,458	)		7,907
Real estate		10,132		(61	)		3,131			(9,616	)		3,586
Private equity investments		11,464		401			1,300			2,994			16,159
Total	$	36,106	$	838		$	3,211		$	(8,485	)	$	31,670

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									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2010
Asset-backed securities	$	6,563	$	466		$	(378	)	$	(3,201	)	$	3,450
Mortgage-backed securities		16,444		1,744			(1,732	)		(5,396	)		11,060
Real estate		9,183		(156	)		1,118			(13	)		10,132
Private equity investments		11,303		(95	)		9,703			(9,447	)		11,464
Total	$	43,493	$	1,959		$	8,711		$	(18,057	)	$	36,106

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2009
Asset-backed securities	$	10,635	$	315		$	6,234		$	(10,621	)	$	6,563
Mortgage-backed securities		22,888		769			13,155			(20,368	)		16,444
Real estate		15,012		(78	)		(5,869	)		118			9,183
Private equity investments		11,131		-			(841	)		1,013			11,303
Total	$	59,666	$	1,006		$	12,679		$	(29,858	)	$	43,493

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

(Thousands of Dollars)	2011			2010
Accumulated Benefit Obligation at Dec. 31	$	368,585		$	338,954
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	370,587		$	340,520
Service cost		7,690			7,008
Interest cost		20,036			19,997
Actuarial loss		27,512			23,086
Benefit payments		(22,458	)		(20,024	)
Obligation at Dec. 31	$	403,367		$	370,587
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	337,421		$	320,913
Actual return on plan assets		29,913			36,532
Employer contributions		5,178			-
Benefit payments		(22,458	)		(20,024	)
Fair value of plan assets at Dec. 31	$	350,054		$	337,421
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(53,313	)	$	(33,166	)
SPS Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	222,849		$	207,981
Prior service cost		2,401			3,906
Total	$	225,250		$	211,887
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	14,761		$	9,294
Noncurrent regulatory assets		210,489			202,593
Total	$	225,250		$	211,887
Measurement date		Dec. 31, 2011			Dec. 31, 2010

(a)   Amounts are recognized in noncurrent liabilities on SPS’ balance sheet.

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	2011			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 $12.9 million was attributable to SPS;

·   In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans, of which $5.2 million was attributable to SPS;

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

·   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 SPS’ net periodic pension cost were:

(Thousands of Dollars)	2011			2010			2009
Service cost	$	7,690		$	7,008		$	5,754
Interest cost		20,036			19,997			20,081
Expected return on plan assets		(26,316	)		(27,542	)		(35,338	)
Amortization of prior service cost		1,505			1,504			1,504
Amortization of net loss		9,046			4,826			1,355
Net periodic pension cost (credit)	$	11,961		$	5,793		$	(6,644	)
Costs not recognized due to effects of regulation		(2,300	)		-			-
Net benefit cost (credit) recognized for financial reporting	$	9,661		$	5,793		$	(6,644	)
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		6.80			6.80			8.50

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to SPS 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 6.68 percent.  The cost calculation uses a market-related valuation of pension assets.  Xcel Energy, including SPS, 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 SPS, 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, including SPS, maintains 401(k) and other defined contribution plans that cover substantially all employees.  The contributions for SPS were approximately $2.0 million in 2011, $2.0 million in 2010 and $1.4 million in 2009.

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Postretirement Health Care Benefits

Xcel Energy, which includes SPS, 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 SPS 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 under the new guidance.

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.  SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates.  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 SPS base 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 SPS’ 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.

The following tables present, for each of the fair value hierarchy levels, SPS’ 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	$	5,387	$	-				$	5,387
Derivatives		-		1,238			-		1,238
Government securities		-		6,156			-		6,156
Corporate bonds		-		5,740			-		5,740
Asset-backed securities		-		-			730		730
Mortgage-backed securities		-		-			2,535		2,535
Preferred stock		-		40			-		40
Commingled funds		-		18,892			-		18,892
Securities lending collateral obligation and other		-		(1,039	)		-		(1,039	)
Total	$	5,387	$	31,027		$	3,265	$	39,679

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	14,108	$	-	$	-	$	14,108
Derivatives		-		1,291		-		1,291
Government securities		-		322		-		322
Corporate bonds		-		6,702		-		6,702
Asset-backed securities		-		-		245		245
Mortgage-backed securities		-		-		1,820		1,820
Preferred stock		-		48		-		48
Commingled funds		-		9,753		-		9,753
Securities lending collateral obligation and other		-		5,657		-		5,657
Total	$	14,108	$	23,773	$	2,065	$	39,946

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

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2011		Gains (Losses)			Gains (Losses)			Settlements, Net		Dec. 31, 2011
Asset-backed securities	$	245	$	(2	)	$	(101	)	$	588	$	730
Mortgage-backed securities		1,820		(157	)		194			678		2,535

								Purchases,
			Net Realized			Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Gains (Losses)		Settlements, Net			Dec. 31, 2010
Asset-backed securities	$	752	$	(25	)	$	75	$	(557	)	$	245
Mortgage-backed securities		4,266		(88	)		332		(2,690	)		1,820

							Purchases,
			Net Realized		Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Gains (Losses)		Gains (Losses)		Settlements, Net			Dec. 31, 2009
Asset-backed securities	$	791	$	-	$	105	$	(144	)	$	752
Mortgage-backed securities		6,362		66		209		(2,371	)		4,266

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

(Thousands of Dollars)	2011			2010
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	50,582		$	49,453
Service cost		1,092			951
Interest cost		2,722			2,899
Medicare subsidy reimbursements		404			712
ERRP proceeds shared with retirees		260			-
Plan participants’ contributions		2,315			2,259
Actuarial loss		4,065			584
Benefit payments		(6,275	)		(6,276	)
Obligation at Dec. 31	$	55,165		$	50,582
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	39,946		$	34,863
Actual return on plan assets		61			4,981
Plan participants’ contributions		2,315			2,259
Employer contributions		3,632			4,119
Benefit payments		(6,275	)		(6,276	)
Fair value of plan assets at Dec. 31	$	39,679		$	39,946
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(15,486	)	$	(10,636	)

(a) Amounts are recognized in noncurrent liabilities on SPS’ balance sheet.

46

(Thousands of Dollars)	2011			2010
SPS Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit:
Net gain	$	(3,281	)	$	(9,455	)
Prior service credit		(131	)		(182	)
Transition obligations		1,545			3,214
Total	$	(1,867	)	$	(6,423	)
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory liabilities	$	(1,867	)	$	-
Noncurrent regulatory liabilities		-			(6,423	)
Total	$	(1,867	)	$	(6,423	)
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 - inital		6.31	%		6.50	%

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 SPS 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 SPS:

	One Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	5,660	$	(4,630	)
Service and interest components		455		(362	)

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 SPS, contributed $49.0 million and $48.4 million during 2011 and 2010, of which $3.6 million and $4.1 million were attributable to SPS.  Xcel Energy expects to contribute approximately $39.1 million during 2012, of which $3.5 million is attributable to SPS.

Plan Amendments — No amendments affecting SPS occurred during 2011 to the Xcel Energy health and welfare benefit plan.

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

(Thousands of Dollars)	2011			2010			2009
Service cost	$	1,092		$	951		$	792
Interest cost		2,722			2,899			3,369
Expected return on plan assets		(3,006	)		(2,639	)		(2,100	)
Amortization of transition obligation		1,669			1,669			1,669
Amortization of prior service cost		(51	)		(51	)		(7	)
Amortization of net loss		855			772			1,277
Net periodic postretirement benefit cost	$	3,281		$	3,601		$	5,000
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 SPS based on Xcel Energy Services Inc. employees’ labor costs.

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Projected Benefit Payments — The following table lists SPS’ 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	$	25,620	$	3,378	$	459	$	2,919
2013		24,352		3,485		485		3,000
2014		25,816		3,670		512		3,158
2015		26,518		3,916		542		3,374
2016		26,922		4,039		576		3,463
2017-2021		144,685		21,025		3,407		17,618

8.  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	$	506		$	250		$	671
Other nonoperating income		11			57			68
Life insurance policy expense		(111	)		(280	)		(475	)
Other income, net	$	406		$	27		$	264

9.  Fair Value of Financial Assets and Liabilities

Fair Value Measurements

SPS had no derivative instruments measured at fair value on a recurring basis as of Dec. 31, 2011 and Dec. 31, 2010.

Derivative Instruments

SPS may enter into derivative instruments, including forward contracts, futures, swaps and options, to reduce risk in connection with changes in interest rates and electric utility commodity prices.

Interest Rate Derivatives — SPS may enter 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 other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during the years ended Dec. 31, 2011 and Dec. 31, 2010 were $0.3 million.

During the fourth quarter of 2009, SPS settled a $25 million notional value interest rate swap.  The interest rate swap was not designated as a hedging instrument, and as such, $2.5 million of changes in fair value of the swap were recorded to earnings for the swap during the year ended Dec. 31, 2009.

Short-Term Wholesale and Commodity Trading Risk — SPS conducts an immaterial amount of short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments.  SPS’ 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 — SPS may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations.  This could include the purchase or sale of energy or energy-related products.  At Dec. 31, 2011 and Dec. 31, 2010, SPS held no commodity derivatives.  Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

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The following table shows the major components of derivative instruments valuation in the balance sheets:

	Dec. 31, 2011				Dec. 31, 2010
	Derivative		Derivative		Derivative		Derivative
	Instruments -		Instruments -		Instruments -		Instruments -
(Thousands of Dollars)	Assets		Liabilities		Assets		Liabilities
Long-term purchased power agreements	$	64,733	$	44,992	$	72,626	$	48,592

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS 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, SPS 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.

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

(Thousands of Dollars)	2011			2010			2009
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(1,675	)	$	(1,847	)	$	(5,559	)
After-tax net realized losses on derivative transactions reclassified into earnings		171			172			3,712
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(1,504	)	$	(1,675	)	$	(1,847	)

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	$	993,314	$	1,176,020	$	897,767	$	989,789

The fair value of SPS’ 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 financial statements since that date and current estimates of fair values may differ significantly.

10.  Rate Matters

Recently Concluded Regulatory Proceedings — NMPRC and PUCT

Base Rate

New Mexico Retail Rate Case — In February 2011, SPS filed a request with the NMPRC seeking to increase New Mexico electric rates approximately $19.9 million.  The rate filing was based on a 2011 test year adjusted for known and measurable changes for 2012, a requested ROE of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent.

In December 2011, the NMPRC approved a black box settlement with new rates effective Jan. 1, 2012.  The settlement increased base rates by $13.5 million.  SPS agreed not to file another base rate case until Dec. 3, 2012 with new final rates from the result of such case not going into effect until Jan. 1, 2014 (Settlement Period).  However, SPS can request to implement interim rates if the NMPRC standard for interim rates is met.  During the Settlement Period, rates are to remain fixed aside from the continued operation of the fuel adjustment clause and certain exceptions for energy efficiency, a rider for an approved renewable portfolio standard regulatory asset, and actual costs incurred for environmental regulations with an effective date after Dec. 31, 2010.  

Texas Retail Rate Case — In May 2010, SPS filed a request with the PUCT seeking to increase Texas electric rates by approximately $71.5 million inclusive of franchise fees.  The rate filing was based on a 2009 test year adjusted for known and measurable changes, a requested ROE of 11.35 percent, an electric rate base of $1.031 billion and an equity ratio of 51.0 percent.  In November 2010, SPS filed an update to the cost of service to reflect the sale of Lubbock facilities which reduced the total request to approximately $63.7 million.

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Effective Feb. 16, 2011, the parties reached an unopposed settlement to resolve all issues in the case and increase base rates by $39.4 million, of which $16.9 million is associated with the transfer of two riders, the TCRF and the PCRF, into base rates.  Effective Jan. 1, 2012, base rates increased by an additional $13.1 million.

SPS agreed not to file another rate case until Sept. 15, 2012.  In addition, SPS cannot file a TCRF application until 2013, and if SPS files a TCRF application before the effective date of rates in its next rate case, it must reduce the calculated TCRF revenue requirement by $12.2 million.

11.  Commitments and Contingent Liabilities

Commitments

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

CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S.  CSAPR is discussed further at Environmental Contingencies.  Xcel Energy is in the process of determining various scenarios to respond to the CSAPR depending on whether the CSAPR is upheld, reversed, or modified.

Fuel Contracts— SPS 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 2033.  SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.  SPS’ 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 SPS under these contracts as of Dec. 31, 2011, are as follows:

(Millions of Dollars)	Dec. 31, 2011
Coal	$	655
Natural gas supply		24
Natural gas storage and transportation		242

Purchased Power Agreements — SPS 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.

SPS has various pay-for-performance contracts with expiration dates through 2024.  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.

Included in electric fuel and purchased power expenses for purchased power agreements were payments for capacity of $39.7 million, $42.0 million and $44.3 million in 2011, 2010 and 2009, respectively.  At Dec. 31, 2011, the estimated future payments for capacity that SPS is obligated to purchase, subject to availability, are as follows:

(Millions of Dollars)
2012	$	37.4
2013		38.1
2014		38.5
2015		39.3
2016		40.0
2017 and thereafter		154.4
Total	$	347.7

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.

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

SPS has determined that certain independent power producing entities are variable interest entities.  SPS 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 purchased power agreements.

SPS 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.  SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  As of Dec. 31, 2011 and Dec. 31, 2010, SPS had approximately 827 MW and 1,027 MW of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.  These agreements have expiration dates through the year 2033.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that expire in 2016 and 2017, respectively.  TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements.  TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

No significant financial support has been, or is in the future, required to be provided to TUCO by SPS, other than contractual payments for delivered coal.  However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs.  SPS has determined that TUCO is a variable interest entity.  SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

Leases— SPS leases a variety of equipment and facilities used in the normal course of business.  These leases, primarily for office space, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases.  Total expenses under operating lease obligations were approximately $58.8 million, $56.6 million and $54.6 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 $54.4 million, $52.8 million and $50.3 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 guidance.  Future commitments under operating leases are:

	Other		Purchased		Total
	Operating		Power Agreement		Operating
(Millions of Dollars)	Leases		Operating Leases (a) (b)		Leases
2012	$	2.8	$	48.3	$	51.1
2013		2.7		44.4		47.1
2014		2.8		44.4		47.2
2015		2.9		44.4		47.3
2016		2.8		44.4		47.2
Thereafter		11.9		744.0		755.9

(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 2033.

Guarantees and Indemnifications

In connection with the purchase and sale agreement of certain electric distribution assets in Lubbock, Texas, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing unknown liabilities.  SPS’ indemnification obligation is capped at $87 million, in the aggregate.  The indemnification provisions for most representations and warranties expired in October 2011.  The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely.  SPS 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.

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Environmental Contingencies

SPS has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites.  In many situations, SPS believes it will recover some portion of these costs through insurance claims.  Additionally, where applicable, SPS 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 SPS, which are normally recovered through the regulated rate process.  To the extent any costs are not recovered through the options listed above, SPS 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.  SPS may sometimes pay all or a portion of the cost to remediate sites where past activities of SPS or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations, including sites of former manufactured gas plants operated by SPS or other entities; and third-party sites, such as landfills, for which SPS is alleged to be a PRP that sent hazardous materials and wastes to that site. 

Asbestos Removal — Some of SPS’ facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed.  SPS 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.  SPS 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 SPS’ power plants.

New Mexico GHG Regulations — In 2010, the EIB adopted two regulations to limit GHG emissions, including CO2 emissions from power plants and other industrial sources.  SPS, other utilities and industry groups have filed separate appeals with the New Mexico Court of Appeals challenging the validity of these two GHG regulations.  The appellate cases have been stayed pending further proceedings before the EIB.

In July 2011, SPS and other parties filed a petition for repeal of each state GHG rule with the EIB.  The EIB held hearings for both repeal petitions in 2011.  The first of these two regulations was repealed by the EIB in February 2012. The second will be reviewed in March 2012.  Unless repealed, the second rule is scheduled to become applicable to SPS beginning in 2013.  Efforts to quantify compliance costs have been suspended pending the outcome on the second rule.

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.

CSAPR — In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S., including Texas.  The CSAPR sets more stringent requirements than the proposed Clean Air Transport Rule and, in contrast to that proposal, specifically requires plants in Texas to reduce their SO2 and annual NOx emissions.  The rule also creates an emissions trading program.  SPS intends to comply by reducing emissions and/or purchasing allowances. 

On Dec. 30, 2011, the U.S. Court of Appeals for the D.C. Circuit issued a stay of the CSAPR, pending completion of judicial review.  The Court is expected to hear the case in April 2012.  SPS anticipates that the court may rule on the challenges to the CSAPR in the second half of 2012.  It is not known at this time whether the CSAPR will be upheld, reversed or will require modifications pursuant to a future Court decision.

If the CSAPR is upheld and unmodified, SPS believes that the CSAPR could ultimately require the installation of additional emission controls on some of SPS’ coal-fired electric generating units.  If compliance is required in a short time frame, SPS may be required to redispatch its system to reduce coal plant operating hours, in order to decrease emissions from its facilities prior to the installation of emission controls.  The expected cost for these scenarios vary significantly and SPS has estimated capital expenditures of approximately $470 million over the next four years for the plant modifications related to the CSAPR requirements.  SPS believes the cost of any required capital investment or possible increased fuel costs would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position or cash flows.

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CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions.  In granting the stay of the CSAPR, the Court specifically noted that the CAIR would remain in place during its pending review of the CSAPR.

Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  In the SPS region, installation of low-NOx combustion control technology began on Tolk Unit 1 in January 2012.  Installation will begin on Tolk Unit 2 at a yet to be determined date.  These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances.  In addition, SPS has sufficient SO2 allowances to comply with CAIR in 2012.  At Dec. 31, 2011, the estimated annual CAIR NOx allowance cost for SPS does not have a material impact on the results of operations, financial position or cash flows.

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.  SPS 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.

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.  SPS 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.  Harrington Units 1 and 2 are potentially subject to BART.  Texas has developed a Regional Haze SIP that finds the CAIR equal to BART for EGUs, and as a result no additional controls for these units beyond the CAIR compliance, described above are required.

Proposed Coal Ash Regulation — SPS’ 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, SPS’ 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.

Cunningham Compliance Order — In December 2011, SPS entered into a final agreement with the NMED that resolved allegations that Cunningham exceeded its permit limits for NOx and failed to report these exceedances as required by its permit.  The settlement was $0.8 million.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for steam production and electric transmission and distribution.  The steam production obligation includes asbestos and ash containment facilities.  This asbestos abatement removal obligation originated in 1973 with the CAA applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  The AROs also have been recorded for SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills and the AROs origination date were the in-service date of the various facilities.

An ARO was recognized for the removal of electric transmission and distribution equipment at SPS, 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 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.

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A reconciliation of the beginning and ending aggregate carrying amounts of SPS’ AROs is shown in the table below for the years ended Dec. 31, 2011 and Dec. 31, 2010:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2011		Liabilities Settled			Accretion		Revisions to Prior Estimates		Ending Balance Dec. 31, 2011
Steam production asbestos	$	19,960	$	(514	)	$	1,357	$	-	$	20,803
Steam production ash containment		345		-			22		352		719
Electric transmission and distribution		826		-			49		4,869		5,744
Total liability	$	21,131	$	(514	)	$	1,428	$	5,221	$	27,266

(Thousands of Dollars)	Beginning Balance Jan. 1, 2010			Liabilities Settled		Accretion			Revisions to Prior Estimates			Ending Balance Dec. 31, 2010
Steam production asbestos	$	18,596		$	-	$	1,272		$	92		$	19,960
Steam production ash containment		417			-		20			(92	)		345
Electric transmission and distribution		(256	)		-		(4	)		1,086			826
Total liability	$	18,757		$		$	1,288		$	1,086		$	21,131

In 2011 and 2010, SPS revised asbestos, ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

Removal Costs — SPS 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, SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.  Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities.  Removal costs as of Dec. 31, 2011 and Dec. 31, 2010, were $74 million and $88 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 SPS’ 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 SPS, 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 SPS, 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 SPS’ 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 SPS’ results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Exelon Wind (formerly John Deere Wind) Complaint—Three lawsuits have been filed by John Deere Wind Energy subsidiaries (JD Wind) arising out of a dispute concerning SPS’ payments for energy produced from JD Wind projects.  The first lawsuit was filed in June 2009 in Texas State District Court against the PUCT.  In this lawsuit, JD Wind filed a petition seeking review of a May 2009 PUCT order denying JD Wind’s request for relief against SPS.  The PUCT has denied all allegations contained in this petition.  On April 21, 2011, JD Wind filed a non-suit of this case dropping the state appeal of the PUCT order so it could pursue its U.S. District Court action.

A second lawsuit was filed in December 2009 by JD Wind against the PUCT in U.S. District Court for the Western District of Texas.  This lawsuit was filed shortly after a declaratory order issued by the FERC stated that the PUCT’s May 2009 order (approving SPS’ payments to JD Wind) is not consistent with the FERC’s regulations.  In this lawsuit, JD Wind seeks declaratory and injunctive relief against the PUCT.  The U.S. District Court issued an order preventing this lawsuit from proceeding pending the outcome of the Texas State District Court proceeding against the PUCT.  As a result of the non-suit of the Texas State District Court proceeding, this case will now move forward with a trial date set for October 2012.

In January 2010, a third lawsuit was filed by JD Wind against SPS in Texas State District Court related to payments made by SPS for energy produced from the JD Wind projects.  It is uncertain when this lawsuit will conclude.  As the damages sought are indeterminate and given the uncertainty surrounding the circumstances of this case, SPS is unable to estimate the range or amount of possible damages.  No accrual has been recorded for this lawsuit nor is it expected that this proceeding will have a material effect on SPS’ results of operations, cash flows or financial position.

Other Contingencies

See Note 10 for further discussion.

12.   Regulatory Assets and Liabilities

SPS’ 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 rates.  If changes in the utility industry or the business of SPS no longer allow for the application of regulatory accounting guidance under GAAP, SPS 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 balance sheets of SPS at Dec. 31, 2011 and Dec. 31, 2010 are:

(Thousands of Dollars)	See Notes		Remaining Amortization Period	Dec. 31, 2011				Dec. 31, 2010
Regulatory Assets				Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)		7	Various	$	14,879	$	214,111	$	9,407	$	203,513
Recoverable deferred taxeson AFUDC recorded in plant (b)		1	Plant lives		-		25,053		-		23,673
Net AROs (d)		11	Plant lives		-		19,920		-		18,882
Conservation programs (e)		1	One to seven years		1,834		10,786		5,201		12,371
Renewable resources and environmental initiatives		11	One to four years		1,458		10,795		2,046		5,719
Losses on reacquired debt		4	Term of related debt		1,228		6,146		1,249		7,092
Deferred income tax adjustment		1, 6	Typically plant lives		-		6,040		-		7,123
Recoverable electric energy costs		1	Less than one year		1,439		-		1,672		-
Other			Various		4,406		1,962		1,972		4,834
Total regulatory assets				$	25,244	$	294,813	$	21,547	$	283,207

(Thousands of Dollars)	See Notes		Remaining Amortization Period	Dec. 31, 2011				Dec. 31, 2010
Regulatory Liabilities				Current		Noncurrent		Current		Noncurrent
Plant removal costs		11	Plant lives	$	-	$	74,402	$	-	$	88,224
Deferred electric energy costs		1	Less than one year		43,295		-		44,588		-
Contract valuation adjustments (c)		1, 9	Term of related contract		4,292		15,450		4,291		19,743
Gain from asset sales		16	Various		4,899		13,229		4,281		18,792
Conservation programs (e)		1	Less than one year		2,222		-		-		-
Other			Various		2,396		2,254		37		8,193
Total regulatory liabilities				$	57,104	$	105,335	$	53,197	$	134,952

(a) Includes the non-qualified pension plan.

(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.

(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.

13.  Segments and Related Information

SPS has only one reportable segment.  SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico.  Revenues from external customers were $1,707.6 million, $1,613.0 million and $1,459.2 million for the years ended Dec. 31, 2011, 2010 and 2009, respectively.

Operating results from the regulated electric utility segment serve as the primary basis for the chief operating decision maker to evaluate the performance of SPS.

14.  Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including SPS.  The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary.  SPS uses the service 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 with the utility subsidiaries.  See Note 4 for further discussion of this borrowing arrangement.

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

(Thousands of Dollars)	2011		2010		2009
Operating revenues:
Electric	$	7,187	$	6,805	$	5,976
Operating expenses:
Purchased power		10,896		9,428		7,751
Other operating expenses — paid to Xcel Energy Services Inc.		118,370		109,111		96,375
Interest expense		83		90		106
Interest income		1		25		495

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

	2011					2010
	Accounts		Accounts			Accounts			Accounts
(Thousands of Dollars)	Receivable		Payable			Receivable			Payable
NSP-Minnesota	$	1,314		$	-		$	1,610		$	-
NSP-Wisconsin		-			-			-			2
PSCo		-			319			-			2,606
Other subsidiaries of Xcel Energy Inc.		-			11,509			-			21,917
	$	1,314		$	11,828		$	1,610		$	24,525

15.  Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2011		June 30, 2011			Sept. 30, 2011			Dec. 31, 2011
Operating revenues	$	381,209		$	433,289		$	522,921		$	370,146
Operating income		29,499			53,433			92,885			24,780
Net income		10,238			24,672			48,581			6,410

	Quarter Ended
(Thousands of Dollars)	March 31, 2010		June 30, 2010			Sept. 30, 2010			Dec. 31, 2010
Operating revenues	$	381,482		$	398,449		$	467,424		$	365,635
Operating income		30,828			54,051			76,937			21,621
Net income		7,699			24,396			39,189			6,783

16.  Sale of Lubbock Electric Distribution Assets

In November 2009, SPS entered into an asset purchase agreement with the city of Lubbock, Texas.  This agreement had set forth that SPS would sell its electric distribution system assets within the city limits to Lubbock Power and Light (LP&L) for approximately $87 million.  The sale and related transactions eliminate the inefficiencies of maintaining duplicate distribution systems, by both SPS and by the city-owned LP&L.

SPS served about 24,000 customers within Lubbock, representing about 25 percent of the total customers in the dually certified service area.  As part of this transaction, SPS will continue to provide wholesale power to meet the electric load for these customers, initially by amending the current wholesale full-requirements contract with WTMPA, which provides service to LP&L through 2019 and then for an additional 25 years under a new contract directly with LP&L when the WTMPA contract terminates.  Both of these wholesale power agreements provide for formula rates that change annually based on the actual cost of service.  The formula rate with WTMPA reflects an initial 10.5 percent ROE.  All or portions of this transaction were reviewed and approved by the PUCT, the NMPRC and the FERC.

Additionally, SPS and the city of Lubbock entered into an amended long-term treated sewage effluent water agreement under which SPS will continue to purchase waste water from the city for cooling SPS’ Jones Station southeast of Lubbock.

In October 2010, the transaction closed resulting in a pre-tax gain of approximately $20 million that has been deferred as a regulatory liability to be shared with retail customers in Texas over a four year period.

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

None.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

SPS 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 SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Controls Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, SPS’ internal control over financial reporting.  SPS maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting.  SPS 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, SPS conducted testing and monitoring of its internal control over financial reporting.  Based on the control evaluation, testing and remediation performed, SPS did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

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

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PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	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
	Statements of Income — For the three years ended Dec. 31, 2011, 2010 and 2009.
	Statements of Cash Flows — For the three years ended Dec. 31, 2011, 2010 and 2009.
	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    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.
3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*	By-laws dated Sept. 29, 1997 (Exhibit 3(b)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
4.01*	Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.02*	First Supplemental Indenture dated March 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.3 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.03*	Second Supplemental Indenture dated Oct. 1, 2001 between SPS and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 23, 2001).
4.04*	Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.05*	Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).
4.06*	Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).
4.07*	Supplemental Trust Indenture dated as of Nov. 1, 2008 between SPS and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $250 million principal amount of Series G Senior Notes, 8.75 percent due 2018  (Exhibit 4.01 of Form 8-K of SPS, dated Nov. 14, 2008 (file no. 001-03789)).
4.08*	Indenture dated as of Aug. 1, 2011 between SPS and U.S, Bank NA, as Trustee.  (Exhibit 4.01 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).
4.09*	Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank NA, as Trustee, creating $200 million principal amount of 4.50 percent First Mortgage Bonds, Series No. 1 due 2041.  (Exhibit 4.02 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).
10.01*+	Xcel Energy Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.02*+	Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

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10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.05*+	Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy  (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*	Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 — Exhibit 3).
10.07*	Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 — Exhibit 5(A)).
10.08*	Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 — Exhibit 5(B)).
10.09*	Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(b)).
10.10*	Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(c)).
10.11*	Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.
10.12*+	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).
10.13*+	Xcel Energy 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).
10.14*+	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).
10.15*+	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).
10.16*+	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).
10.17*+	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).
10.18*+	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).
10.19*+	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).
10.20*+	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).
10.21*	Credit Agreement, dated as of March 17, 2011 among SPS 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).
10.22*	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).
10.23+	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).
10.24+	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.
101t	The following materials from SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2011 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Statements of Income, (ii) the Statements of Cash Flow, (iii) the Balance Sheets, (iv) the Statements of Stockholder’s Equity and Comprehensive Income, (v) Notes to Condensed Financial Statements, and (vi) document and entity information.

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SCHEDULE II

SOUTHWESTERN PUBLIC SERVICE CO.

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2011, 2010 AND 2009

(amounts in thousands)

				Additions
				Charged to			Charged to			Deductions
	Balance at			Costs and			Other			from			Balance at
	Jan. 1			Expenses			Accounts (a)			Reserves (b)			Dec. 31
Allowance for bad debts:
2011		$	5,095		$	3,655		$	1,139		$	4,509		$	5,380
2010			4,415			3,990			998			4,308			5,095
2009			4,688			3,765			934			4,972			4,415

(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.

SOUTHWESTERN PUBLIC SERVICE CO.

/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 signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.

/s/ C. RILEY HILL	/s/ BENJAMIN G.S. FOWKE III
C. Riley Hill	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

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

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