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.

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.

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.

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.

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.

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.