13. Commitments and Contingent Liabilities

Commitments

Capital Commitments - Xcel Energy has made commitments in connection with a portion of its projected capital expenditures. Xcel Energy's capital commitments primarily relate to the following major projects:

Nuclear Lifecycle Management and Extended Power Uprates - NSP-Minnesota is pursuing improvements to make sure the plants operate safely until the end of their extended licensed life and is making capacity increases of the Monticello and Prairie Island generating plants that could total up to approximately 188 MW. The MPUC approved the CON for the extended power uprate for Monticello in 2008. The license amendment application was filed with the NRC in November 2008, but a concern was raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance. In October 2011, the Advisory Committee recommended that all licensing actions that credit the use of containment accident pressure be suspended until the causes and risks of Japan's Fukushima incident are better understood. NSP-Minnesota has rescheduled the remaining equipment changes needed to complete the Monticello power uprate projects during the planned spring 2013 refueling outage.

The MPUC approved an extended power uprate for the Prairie Island Units in 2009. Analysis of recent extended power uprate submittals to the NRC concluded that significant additional design work beyond current schedule and cost plan estimates are now being required to submit a successful application. As a result, NSP-Minnesota is completing an economic and new project design analysis to determine project impacts and anticipates submitting a Change in Circumstances filing with the MPUC in the first quarter of 2012.

CapX2020 - CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy that have proposed several groups of transmission projects to be complete by 2020. Group 1 project investments consist of four transmission lines. Major construction began in 2010 on the Group 1 transmission lines with an expected completion date in 2015. NSP System's investment depends on the routes and configurations approved by affected state commissions. The remainder of the costs will be born by other utilities in the upper Midwest.

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

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

The estimated minimum purchases for Xcel Energy under these contracts as of Dec. 31, 2011 are as follows:

(Millions of Dollars)	Dec. 31, 2011
Coal	$	3,683
Nuclear fuel		1,546
Natural gas supply		1,122
Natural gas storage and transportation		2,755

Estimated coal requirements at Dec. 31, 2011 have been adjusted to account for Sherco Unit 3, which was shut down in November 2011 after experiencing a significant failure of its turbine, generator and exciter systems. It is uncertain when Sherco Unit 3 will recommence operations. See Note 5 for further discussion.

Purchased Power Agreements- Xcel Energy 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.

NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through 2033. 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 $325.3 million, $426.7 million and $461.3 million in 2011, 2010 and 2009, respectively. At Dec. 31, 2011, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows:

(Millions of Dollars)
2012	$	275.5
2013		227.2
2014		224.9
2015		198.6
2016		148.7
2017 and thereafter		404.0
Total	$	1,478.9

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, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities that own natural gas or biomass fueled power plants for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the subsidiaries procure the natural gas required to produce the energy that they purchase. These specific purchased power agreements create a variable interest in the associated independent power producing entity.

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

Xcel Energy 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. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities' economic performance. Xcel Energy had approximately 3,773 MW and 4,101 MW of capacity under long-term purchased power agreements as of Dec. 31, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 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.

Low-Income Housing Limited Partnerships - Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin's low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners' proportional equity ownership. These limited partnerships are designed to qualify for low-income housing tax credits, and Eloigne and NSP-Wisconsin generally receive a larger allocation of the tax credits than the general partners at inception of the arrangements. Xcel Energy Inc. has determined that Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities' economic performance, and therefore Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements.

Equity financing for these entities has been provided by Eloigne and NSP-Wisconsin and the general partner of each limited partnership, and Xcel Energy's risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is in the future, required to be provided to the limited partnerships by Eloigne or NSP-Wisconsin. Mortgage-backed debt typically comprises the majority of the financing at inception of each limited partnership and is paid over the life of the limited partnership arrangement. Obligations of the limited partnerships are generally secured by the housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to Xcel Energy Inc. or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of Xcel Energy Inc. or its subsidiaries.

Amounts reflected in Xcel Energy's consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships include the following:

(Thousands of Dollars)	Dec. 31, 2011		Dec. 31, 2010
Current assets	$	4,034	$	3,794
Property, plant and equipment, net		90,914		97,602
Other noncurrent assets		8,053		8,236
Total assets	$	103,001	$	109,632

Current liabilities	$	12,297	$	11,884
Mortgages and other long-term debt payable		48,863		53,195
Other noncurrent liabilities		8,278		8,333
Total liabilities	$	69,438	$	73,412

Leases - Xcel Energy leases a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. The assets and liabilities at the inception of the capital leases are recorded at the lower of fair market value or the present value of future lease payments and are amortized over their actual contract term.

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

PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $152.7 million and $149.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2011 and 2010, respectively. Xcel Energy Inc. eliminates 50 percent of the capital lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.'s equity investment in WYCO.

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

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

The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations for Xcel Energy were approximately $204.8 million, $197.4 million, and $209.5 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 $160.5 million, $163.7 million, and $171.3 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 accounting guidance. Future commitments under operating and capital leases are:

	Other		Purchased		Total
	Operating		Power Agreement		Operating
(Millions of Dollars)	Leases		Operating Leases (a) (b)		Leases		Capital Leases
2012	$	26.6	$	159.0	$	185.6	$	18.2
2013		24.8		173.5		198.3		18.0
2014		24.3		180.6		204.9		18.0
2015		23.2		182.0		205.2		17.9
2016		18.2		173.9		192.1		17.2
Thereafter		89.6		1,908.7		1,998.3		306.2
Total minimum obligation								395.5
Interest component of obligation								(280.5	)
Present value of minimum obligation							$	115.0		(c)

(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.

(c)	Future commitments exclude certain amounts related to Xcel Energy's 50 percent ownership interest in WYCO.

Technology Agreements - Xcel Energy has a contract that extends through Sept. 30, 2015 with IBM for information technology services. The contract is cancelable at Xcel Energy's option, although there are financial penalties for early termination. In 2011, Xcel Energy paid IBM $93.6 million under the contract which included $1.4 million for other project business. In 2010, Xcel Energy paid IBM $95.6 million under the contract which included $2.0 million for other project business.

Xcel Energy's contract with Accenture for information technology services extends through Jan. 31, 2017. It is cancelable at Xcel Energy's option, although Xcel Energy would be obligated to pay 50 percent of the contract value for early termination. In 2011, Xcel Energy paid Accenture $15.2 million under the contract which included $5.6 million for other project business. In 2010, Xcel Energy paid Accenture $22.7 million under the contract which included $8.4 million for other project business.

Committed minimum payments under these obligations are as follows:

	IBM		Accenture
(Millions of Dollars)	Agreement		Agreement
2012	$	19.2	$	8.7
2013		17.6		8.4
2014		17.2		8.2
2015		11.9		8.2
2016 and thereafter		-		8.1

Guarantees and Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.'s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of Dec. 31, 2011, Xcel Energy Inc. and its subsidiaries have no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

Guarantees and Surety Bonds

The following table presents guarantees and bond indemnities issued and outstanding, including those guarantees related to Xcel Energy Wholesales Group Inc., Seren, UE, Viking, and Xcel Energy Argentina Inc., which are components of discontinued operations, as of Dec. 31, 2011:

(Millions of Dollars)	Guarantor	Guarantee Amount		Current Exposure		Triggering Event
Guarantee of the indemnification obligations of Xcel Energy Wholesale Group Inc. under a stock purchase agreement (e)	Xcel Energy Inc.	$	17.5	$	17.5	(b)

Guarantee of the indemnification obligations of Xcel Energy Argentina Inc. under a stock purchase agreement (d)	Xcel Energy Inc.		14.7		-	(b)

Guarantee of the indemnification obligations of various Xcel Energy Inc. subsidiaries under different asset purchase agreements (d)	Xcel Energy Inc.		25.5		-	(b)

Guarantee of customer loans for the Farm Rewiring Program (f)	NSP-Wisconsin		1.0		0.5	(c)

Guarantee of the indemnification obligations of Xcel Energy Services Inc. under the aircraft leases (g)	Xcel Energy Inc.		8.3		-	(a)

Guarantee benefiting Young Gas Storage Company Ltd. (f)	Xcel Energy Inc.		0.5		-	(a)
Total guarantees issued		$	67.5	$	18.0

Guarantee performance and payment of surety bonds for Xcel Energy Inc. and its subsidiaries (j) (k)	Xcel Energy Inc.	$	31.2	(h)		(i)

(a)	Nonperformance and/or nonpayment.

(b)	Losses caused by default in performance of covenants or breach of any warranty or representation in the purchase agreement.

(c)	The debtor becomes the subject of bankruptcy or other insolvency proceedings.

(d)	The term of this guarantee is continuing. Certain representations and warranties relating to due organization, transaction authorization and tax matters survive indefinitely. As of Dec. 31, 2011, no claims have been made.

(e)	The indemnification provisions of the guarantee expired in 2010. As of Dec. 31, 2011, there is a pending indemnification claim causing the guarantee liability to remain outstanding until the final resolution.

(f)	The term of this guarantee is continuing.

(g)	The term of this guarantee expires in 2012 when the associated leases expire. At the time of renewal of the aircraft leases, the related guarantees will also be renewed.

(h)	Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.

(i)

Failure of Xcel Energy Inc. or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted.

(j)

Xcel Energy Inc. has on ongoing agreement to indemnify an insurance company in connection with surety bonds they may issue or have issued for UE up to $80 million. Xcel Energy Inc.'s indemnification will be triggered only in the event that UE has failed to meet its obligations to the surety company.

(k)	The expiration date of the surety bonds is project based. Accordingly, the surety bonds expire in conjunction with the completion of the related projects.

Indemnification Agreements

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.

In connection with the acquisition of the 201 MW Nobles wind project, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties. NSP-Minnesota's indemnification obligation is capped at $20 million, in the aggregate. The indemnification obligation expires in March 2013. NSP-Minnesota has not recorded a liability related to this indemnity.

In connection with the acquisition of 900 MW of gas-fired generation from subsidiaries ofCalpine Development Holdings Inc., PSCo agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties. The aggregate liability for PSCo pursuant to these indemnities is not subject to a capped dollar amount. The indemnification obligation expires in December 2012. PSCo has not recorded a liability related to this indemnity.

Xcel Energy Inc. and its subsidiaries provide other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including due organization, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.'s and its subsidiaries' obligations under these agreements may be limited in terms of time and amount. The maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated.

Environmental Contingencies

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

MGP Sites

Ashland MGP Site - NSP-Wisconsin has been named a PRP for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior's Chequamegon Bay adjoining the park (the Sediments).

The EPA issued its Record of Decision (ROD) in September 2010, which documents the remedy that the EPA has selected for the cleanup of the Ashland site. In April 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future cleanup at the site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intend to conduct or pay for the cleanup. On June 30, 2011, NSP-Wisconsin submitted a settlement offer to the EPA related to the future cleanup of the Ashland site. On July 14, 2011, the EPA informed NSP-Wisconsin and the other PRPs that it was rejecting all of their individual offers and can now choose to initiate enforcement actions at any time. Despite this decision, the EPA also indicated a willingness to continue settlement negotiations with NSP-Wisconsin. Settlement negotiations are ongoing.

At Dec. 31, 2011 and Dec. 31, 2010, NSP-Wisconsin had recorded a liability of $104.3 million and $97.5 million, respectively, based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $26.6 million and $4.8 million, respectively, was considered a current liability. NSP-Wisconsin's potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change until after negotiations or litigation with the EPA and other PRPs are fully resolved. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include, but are not limited to, the cleanup approach implemented, which party implements the cleanup, the timing of when the cleanup is implemented and the contributions, if any, by other PRPs.

NSP-Wisconsin has deferred, as a regulatory asset, the estimated site remediation expenses and spending to date less insurance and rate recoveries, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process. Under an existing PSCW policy with respect to recovery of remediation costs for MGPs, utilities have recovered remediation costs in natural gas rates, amortized over a four- to six-year period. The PSCW has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation. In a recent rate case decision, the PSCW recognized the potential magnitude of the future liability for, and circumstances of, the cleanup at the Ashland site and indicated it may consider alternatives to its established MGP site cleanup cost accounting and cost recovery guidelines for the Ashland site in a future proceeding. NSP-Wisconsin is working with the PSCW Staff to develop alternatives for consideration by the PSCW.

Other MGP Sites- Xcel Energy is currently involved in investigating and/or remediating several other MGP sites where hazardous or other regulated materials may have been deposited. Xcel Energy has identified 8 sites, where former MGP activities have or may have resulted in actual site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any ultimate remediation that may be conducted. Xcel Energy anticipates that the majority of the remediation at these sites will continue through at least 2014. For these sites, Xcel Energy had accrued $3.9 million and $3.2 million at Dec. 31, 2011 and Dec. 31, 2010, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs actually incurred at these sites. Xcel Energy anticipates that any amounts actually spent will be fully recovered from customers.

Asbestos Removal - Some of Xcel Energy's facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. Xcel Energy 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. Xcel Energy 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 Xcel Energy's 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. For Xcel Energy, the rule applies to Minnesota, Wisconsin and Texas. The CSAPR sets more stringent requirements than the proposed CATR 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. Xcel Energy 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. Xcel Energy 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, Xcel Energy 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 may 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.

If the CSAPR is upheld and unmodified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at NSP-Minnesota's Sherco plant, which is estimated to cost a total of $10 million through 2014, and system operating changes to the Black Dog and the Sherco plants. If available, NSP-Minnesota would also consider allowance purchases. In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the U.S. Court of Appeals for the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota. NSP-Minnesota contends that the EPA's method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas. If successful, additional allowances would reduce NSP-Minnesota's costs to comply with the reductions that may be imposed by the CSAPR.

If the CSAPR is upheld and unmodified, NSP-Wisconsin would likely make a combination of system operating changes and allowance purchases. NSP-Wisconsin estimates the cost of compliance would be $0.2 million, and expects the cost of any required capital investment will be recoverable from customers.

CAIR - In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The CAIR applies to Texas and Wisconsin. The CAIR does not currently apply in Minnesota because the Court specifically found that the EPA had not adequately justified the application of the CAIR to Minnesota. 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. To comply with the CAIR in 2012, NSP-Wisconsin will likely make a combination of system operating changes and allowance purchases, if available. 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 Xcel Energy does not have a material impact on the results of operations, financial position or cash flows.

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. Xcel Energy believes these costs would be recoverable through regulatory mechanisms, and it does not expect a material impact on its results of operations, financial position or cash flows.

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

Minnesota Mercury Legislation - Under the 2006 mercury legislation, NSP-Minnesota installed sorbent control systems at the Sherco Unit 3 and A.S. King generating plants, with project costs collected through the MCR rider in 2010. Subsequently, in the 2010 Minnesota electric rate case, the costs of these projects were moved into base rates as part of the interim rates effective Jan. 2, 2011. NSP-Minnesota has also obtained MPUC approval to install mercury controls on Sherco Units 1 and 2 by the end of 2014.

For Sherco Units 1 and 2, NSP-Minnesota has incurred $1.5 million in study costs to date and spent $0.6 million through Dec. 31, 2011 for testing and studying of technologies. At Dec. 31, 2011, the estimated annual testing and study cost is $0.5 million. NSP-Minnesota projects installation costs of $12.0 million for the mercury controls on the units and O&M expense of $10.0 million per year beginning in 2014. NSP-Minnesota believes these costs would be recoverable through regulatory mechanisms.

Industrial Broiler (IB) MACT Rules - In March 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin's Bay Front units 1 and 2. On Dec. 23, 2011, the EPA proposed reconsideration of certain provisions of the final rule. The estimated capital cost of $9.0 million per unit, which is currently targeted for 2014, is dependent on the outcome of the reconsideration proceedings.

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

Regional Haze Rules - In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Xcel Energy generating facilities in several states 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.

PSCo

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

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

NSP-Minnesota

In December 2009, the MPCA Citizens Board approved the Regional Haze SIP, which has been submitted to the EPA for approval. The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The MPCA's BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2. The combustion controls have been installed on Sherco Units 1 and 2, and the scrubber upgrades are scheduled to be installed by 2015. At this time, the estimated cost for meeting the BART and other CAA requirements is approximately $50 million of which $20 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2. Xcel Energy anticipates that all costs associated with BART compliance will be fully recoverable.

In June 2011, the EPA provided comments to the MPCA on the SIP, stating the EPA's preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2. The MPCA has since proposed that the CSAPR should be considered BART for EGUs and the EPA has proposed that states be allowed to find that CSAPR compliance meets BART requirements for EGUs, and specifically that Minnesota's proposal to find the CSAPR to meet BART requirements should be approved, if finalized by the state. It is not yet known what the final requirements will be. NSP-Minnesota does not expect that a finding that the CSAPR meets BART requirements would result in changes to the control equipment plans described above, and has requested that the MPCA retain its 2009 BART determination.

In October 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota's Sherco Units 1 and 2. The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and, if so, whether the level of controls proposed by the MPCA is appropriate. In its Jan. 25, 2012 notice concerning its review of Minnesota's Regional Haze SIP, the EPA noted that it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the Reasonably Attributable Visibility Impairment (RAVI) program. It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.

SPS

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.

Federal Clean Water Act (CWA) Section 316 (b) - The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In April 2011, the EPA published the proposed rule that sets prescriptive standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. Xcel Energy provided comments to the proposed rule, which is expected to be finalized in late 2012. Due to the uncertainty of the final regulatory requirements, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

As part of NSP-Minnesota's 2009 CWA permit renewal for the Black Dog plant, the MPCA required the submission of a plan for compliance with the CWA. The compliance plan was submitted for MPCA review and approval in April 2010. The MPCA is currently reviewing the proposal in consultation with the EPA.

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

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

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.

NSP-Minnesota NOV - In June 2011, NSP-Minnesota received an NOV from the EPA alleging violations of the NSR requirements of the CAA at the Sherco plant and Black Dog plant in Minnesota. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid 2000s should have required a permit under the NSR process. NSP-Minnesota believes it has acted in full compliance with the CAA and NSR process. NSP-Minnesota also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. NSP-Minnesota disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this NOV.

Asset Retirement Obligations

Recorded AROs - AROs have been recorded for plant related to nuclear production, steam production, wind production, electric transmission and distribution, natural gas transmission and distribution and office buildings. The steam production obligation includes asbestos, ash-containment facilities, radiation sources and decommissioning. The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota, PSCo and SPS. NSP-Minnesota also recorded asbestos recognition for its general office building. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs also have been recorded for NSP-Minnesota, PSCo and SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination dates on the ARO recognition for ash-containment facilities at steam plants was the in-service dates of the various facilities. Additional AROs have been recorded for NSP-Minnesota and PSCo steam production plant related to radiation sources in equipment used to monitor the flow of coal, lime and other materials through feeders.

Xcel Energy recognized an ARO for the retirement costs of natural gas mains at NSP-Minnesota, NSP-Wisconsin and PSCo. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment at NSP-Minnesota, NSP-Wisconsin, PSCo and 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 and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

For the nuclear assets, the ARO associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originated with the in-service date of the facility. See Note 14 for further discussion of nuclear obligations.

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

	Beginning									Revisions			Ending
	Balance		Liabilities		Liabilities					to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2011		Recognized		Settled			Accretion		Estimates			Dec. 31, 2011
Electric plant
Steam production asbestos	$	93,629	$	-	$	(514	)	$	5,958	$	(44,731	)		$	54,342
Steam production ash containment		19,688		-		-			919		20,551				41,158
Steam production radiation sources		166		-		-			12		(39	)			139
Nuclear production decommissioning		809,474		-		-			57,641		615,626	(a)			1,482,741
Wind production		38,553		-		-			1,962		-				40,515
Electric transmission and distribution		5,727		-		-			290		24,687				30,704
Natural gas plant
Gas transmission and distribution		996		-		-			63		-				1,059
Common and other property
Common general plant asbestos		1,077		-		-			58		-				1,135
Total liability	$	969,310	$	-	$	(514	)	$	66,903	$	616,094			$	1,651,793

(a)

The increase is primarily due to the completion of NSP-Minnesota's triennial nuclear decommissioning study, which reflects an increase in the estimated cost of retirement, increase in the escalation rates for each nuclear unit and a decrease in the discount rate used to calculate the net present value of the future cash flows.

The fair value of NSP-Minnesota's legally restricted assets, for purposes of settling the nuclear ARO, was $1.3 billion as of Dec. 31, 2011, including external nuclear decommissioning investment funds and internally funded amounts.

In 2011, revisions were made for nuclear, asbestos, ash-containment facilities, radiation sources and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

	Beginning									Revisions			Ending
	Balance		Liabilities		Liabilities					to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2010		Recognized		Settled			Accretion		Estimates			Dec. 31, 2010
Electric plant
Steam production asbestos	$	95,093	$	3,771	$	(2,330	)	$	6,037	$	(8,942	)	$	93,629
Steam production ash containment		17,552		32		-			903		1,201			19,688
Steam production radiation sources		176		-		-			12		(22	)		166
Nuclear production decommissioning		758,923		-		-			50,551		-			809,474
Wind production		7,751		25,671		-			592		4,539			38,553
Electric transmission and distribution		27		-		-			12		5,688			5,727
Natural gas plant
Gas transmission and distribution		936		-		-			60		-			996
Common and other property
Common general plant asbestos		1,021		-		-			56		-			1,077
Total liability	$	881,479	$	29,474	$	(2,330	)	$	58,223	$	2,464		$	969,310

The fair value of NSP-Minnesota's legally restricted assets, for purposes of settling the nuclear ARO, was $1.4 billion as of Dec. 31, 2010, including external nuclear decommissioning investment funds and internally funded amounts.

In 2010, revisions were made for asbestos, ash-containment facilities, wind turbines, radiation sources and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

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

Removal Costs - Xcel Energy records a regulatory liability for the plant removal costs of other generation, transmission and distribution facilities of its utility subsidiaries. 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, the utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.

The accumulated balances by entity were as follows at Dec. 31:

(Millions of Dollars)	2011		2010
NSP-Minnesota	$	382	$	400
NSP-Wisconsin		109		107
PSCo		380		385
SPS		74		88
Total Xcel Energy	$	945	$	980

Nuclear Insurance

NSP-Minnesota's public liability for claims resulting from any nuclear incident is limited to $12.6 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $375 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $12.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $117.5 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $17.5 million per reactor during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC's last adjustment was effective April 2010.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.25 billion for each of NSP-Minnesota's two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $15.7 million for business interruption insurance and $33.6 million for property damage insurance if losses exceed accumulated reserve funds.

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 Xcel Energy's financial position and results of operations.

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. - In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against the following utilities, including Xcel Energy, 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 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 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 believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on Xcel Energy's consolidated 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 believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on Xcel Energy's consolidated results of operations, cash flows or financial position. No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

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

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

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

Merricourt Wind Project Litigation - On April 1, 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota's decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco's nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. As a result, NSP-Minnesota recorded a $101 million deposit in the first quarter 2011, which was collected in April 2011. On May 5, 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. On that same day, enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract. NSP-Minnesota believes enXco's lawsuit is without merit and has filed a motion to dismiss. On Sept. 16, 2011, the U.S. District Court denied the motion to dismiss. The trial is set to begin in late 2012 or early 2013. While Xcel Energy believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on Xcel Energy's consolidated results of operations, cash flows or financial position. No accrual has been recorded for this matter.

Other Contingencies

See Note 12 for further discussion.