NOTE 18 - COMMITMENTS AND CONTINGENCIES

Long-Term Power Purchases Vermont Yankee: We are purchasing our entitlement share of Vermont Yankee plant output through the VY PPA between Entergy-Vermont Yankee and VYNPC. We have one secondary purchaser that receives less than 0.5 percent of our entitlement. Our contract for purchases expires on March 21, 2012. While this has been a significant concern in the past, the short span of time before the contract's end and changes in the regional power market have decreased the risk the company might face. The New England Market currently has a significant surplus of available energy and generating capacity, and due to significant reductions in natural gas prices, electrical energy is available at competitive rates.

In recent years, prices under the VY PPA increased $1 per megawatt-hour each calendar year and were $44 per MWh in 2011 and are $45 per MWh in 2012. The VY PPA contains a provision known as the “low market adjuster” that calls for a downward adjustment in the contract price if market prices for electricity fall by defined amounts. Purchases in 2012 are expected to be approximately $15.6 million. The total cost estimate is based on projected MWh purchase volume at PPA rates, plus an estimate of VYNPC's costs and credits, primarily net interest, nuclear insurance refunds and administration. Actual amounts may differ. See Note 4 – Investments in Affiliates for additional information on the VY PPA.

A summary of the VY PPA, including the actual amount for 2011 and the estimated average amount 2012, is shown in the table below. The total cost estimate is based on projected MWh purchase volume at PPA rates, plus an estimate of VYNPC's costs and credits, primarily net interest, nuclear insurance refunds and administration. Actual amounts may differ.

				Estimated Average
	2011			2012
Average capacity acquired		180			180
Share of VYNPC entitlement		34.80	%		34.80	%
Annual energy charge per MWh	$	44.12		$	45.15
Average total cost per MWh	$	43.92		$	45.86
Contract period termination				March 2012

Entergy-Vermont Yankee has no obligation to supply energy to VYNPC over its entitlement share of plant output, so we receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating. We purchase replacement energy as needed when the Vermont Yankee plant is not operating or is operating at reduced levels. We typically acquire most of this replacement energy through forward purchase contracts and account for those contracts as derivatives. Our total VYNPC purchases were $62.4 million in 2011, $58.7 million in 2010 and $64 million in 2009.

On June 22, 2010, we, along with GMP, made a claim to Entergy-Vermont Yankee under the September 6, 2001 VY PPA. The parties claim that Entergy-Vermont Yankee breached its obligations under the agreement by failing to detect and remedy the conditions that resulted in cooling tower-related failures at the Vermont Yankee nuclear plant in 2007 and 2008. Those failures caused us and GMP to incur substantial incremental replacement power costs.

We are seeking recovery of the incremental costs from Entergy-Vermont Yankee under the terms of the VY PPA based upon the results of certain reports, including an NRC inspection, in which the inspection team found that Entergy-Vermont Yankee, among other things, did not have sufficient design documentation available to help it prevent problems with the cooling towers. The NRC released its findings on October 14, 2008. In considering whether to seek recovery, we also reviewed the 2007 and 2008 root cause analysis reports by Entergy-Vermont Yankee and a December 22, 2008 reliability assessment provided by Nuclear Safety Associates to the State of Vermont. Entergy-Vermont Yankee disputes our claim.

On January 10, 2012, after failing to reach a resolution of the matter with Entergy-Vermont Yankee, we and GMP filed a lawsuit in Vermont Superior Court in Windham County. The lawsuit seeks compensatory damages of $6.6 million to cover increased power costs and lost capacity payments resulting from the tower failures, plus interest. Our portion of this claim is $4.3 million. On January 18, 2012, Defendant Entergy-Vermont Yankee filed a notice of removal of the case to the United States District Court for the District of Vermont, asserting diversity of citizenship and federal jurisdiction over a federal question. The defendant also filed an answer to the complaint, and asserted affirmative defenses and demanded a jury trial. The case is now pending in the federal court. We cannot predict the outcome of this matter at this time.

The VY PPA contains a formula for determining the VYNPC power entitlement following an uprate in 2006 that increased the plant's operating capacity by approximately 20 percent. VYNPC and Entergy-Vermont Yankee are seeking to resolve certain differences in the interpretation of the formula. At issue is how much capacity and energy VYNPC Sponsors receive under the VY PPA following the uprate. Based on VYNPC's calculations the VYNPC Sponsors should be entitled to slightly more capacity and energy than they have been receiving under the VY PPA since the uprate. We cannot predict the outcome of this matter at this time.

Coincident with the termination of the VY PPA on March 21, 2012 is the termination of the Vermont Yankee plant's original 40-year operating license. While the NRC voted 4-0 to approve the 20-year license extension through March 21, 2032 requested by Entergy-Vermont Yankee, under Act 160, a Vermont law enacted in 2006, a favorable Vermont legislative vote was required for the Vermont Yankee plant to continue operations after March 21, 2012. On February 24, 2010, in a non-binding vote, the Vermont Senate voted against allowing the PSB to consider granting the Vermont Yankee plant another 20-year operating license.

In a federal lawsuit filed in U.S. District Court for the District of Vermont on April 18, 2011, Entergy-Vermont Yankee contended that the state was improperly attempting to interfere with its relicensing and sought a judgment to prevent the state of Vermont from forcing the Vermont Yankee nuclear power plant to cease operation on March 21, 2012. The complaint sought both declaratory and injunctive relief, and contended that Vermont's attempts to close the plant are preempted by the Atomic Energy Act, the Federal Power Act and the Commerce Clause of the U.S. Constitution.

During the week of September 12, 2011, the U.S. District Court for the District of Vermont held a trial on the merits of Entergy-Vermont Yankee's complaint.

On January 19, 2012 the U.S. District Court for the District of Vermont issued a decision ruling against the state of Vermont. The effect of the ruling is that the state is prohibited under federal law from taking any action to compel the plant to shut down after March 21, 2012 because it failed to obtain legislative approval (under the provisions of Act 160). The state of Vermont was precluded from shutting the plant down for safety-related reasons. On February 18, 2012, the state filed a notice of appeal with the 2nd U.S. Circuit Court of Appeals in New York. Meanwhile, Vermont Yankee still must obtain a Certificate of Public Good from the PSB to gain a 20-year license extension. We are participants in this docket due to a prior revenue-sharing agreement. That revenue-sharing arrangement provides in part that in the event that Entergy extends the operation of the plant pursuant to an extension of its NRC license, Entergy agrees to share with VYNPC 50 percent of the “Excess Revenue” for 10 years commencing on March 13, 2012.

On February 27, 2012, Entergy filed notice with the U.S. District Court for the District of Vermont saying that it would ask the 2nd U.S. Circuit Court of Appeals to review a decision. It will appeal a federal judge's order allowing the plant to stay open past its originally scheduled shutdown date, and will ask the original judge to revisit his order and prevent the state of Vermont from barring the future storage of spent nuclear fuel at the plant. Entergy has informed the PSB that it intends to continue to operate the plant pending a final PSB ruling on its operation. The PSB has not yet indicated whether it will require the plant to cease operations after March 21.

Hydro-Québec: We continue to purchase power under the Hydro-Québec VJO power contract. The VJO power contract has been in place since 1987 and purchases began in 1990. Related contracts were subsequently negotiated between us and Hydro-Québec, altering the terms and conditions contained in the original contract by reducing the overall power requirements and related costs. The VJO power contract runs through 2020, but our purchases under the contract end in 2016. The average level of deliveries under the current contract decreases by approximately 20 percent after 2012, and by approximately 84 percent after 2015.

The annual load factor is 75 percent for the remainder of the VJO power contract, unless the contract is changed or there is a reduction due to the adverse hydraulic conditions described below.

There are two sellback contracts with provisions that apply to existing and future VJO power contract purchases. The first resulted in the sellback of 25 MW of capacity and associated energy through April 30, 2012, which has no net impact currently since an identical 25 MW purchase was made in conjunction with the sellback. We have a 23 MW share of the 25 MW sellback. However, since the sellback ends six months before the corresponding purchase ends, the first sellback will result in a 23 MW increase in our capacity and energy purchases for the period from May 1, 2012 through October 31, 2012.

A second sellback contract provided benefits to us that ended in 1996 in exchange for two options to Hydro-Québec. The first option was never exercised and expired December 31, 2010. The second gives Hydro-Québec the right, upon one year's written notice, to curtail energy deliveries in a contract year (12 months beginning November 1) from an annual capacity factor of 75 to 50 percent due to adverse hydraulic conditions as measured at certain metering stations on unregulated rivers in Québec. This second option can be exercised five times through October 2015 but due to the notice provision there is a maximum remaining application of three times available. To date, Hydro-Québec has not exercised this option. We have determined that this second option is not a derivative because it is contingent upon a physical variable.

There are specific contractual provisions providing that in the event any VJO member fails to meet its obligation under the contract with Hydro-Québec, the remaining VJO participants will “step-up” to the defaulting party's share on a pro-rata basis. As of December 31, 2011, our obligation is about 47 percent of the total VJO power contract through 2016, and represents approximately $226.8 million, on a nominal basis.

In accordance with FASB's guidance for guarantees, we are required to disclose the “maximum potential amount of future payments (undiscounted) the guarantor could be required to make under the guarantee.” Such disclosure is required even if the likelihood is remote. With regard to the “step-up” provision in the VJO power contract, we must assume that all members of the VJO simultaneously default in order to estimate the “maximum potential” amount of future payments. We believe this is a highly unlikely scenario given that the majority of VJO members are regulated utilities with regulated cost recovery. Each VJO participant has received regulatory approval to recover the cost of this purchased power contract in its most recent rate applications. Despite the remote chance that such an event could occur, we estimate that our undiscounted purchase obligation would be an additional $265.2 million for the remainder of the contract, assuming that all members of the VJO defaulted by January 1, 2012 and remained in default for the duration of the contract. In such a scenario, we would then own the power and could seek to recover our costs from the defaulting members or our retail customers, or resell the power in the wholesale power markets in New England. The range of outcomes (full cost recovery, potential loss or potential profit) would be highly dependent on Vermont regulation and wholesale market prices at the time.

Total purchases from Hydro-Québec were $61.9 million in 2011, $63 million in 2010 and $63.1 million in 2009. Annual capacity costs decreased by $2.2 million starting November 1, 2009, and that cost reduction will continue for six contract years. An additional annual $0.9 million capacity cost reduction started November 1, 2011, of which $0.4 will continue for five contract years. A summary of the Hydro-Québec actual charges for 2011 and the projected charges for the remainder of the contract are shown in the table below. Projections are based on certain assumptions including availability of the transmission system and scheduled deliveries, so actual amounts may differ (dollars in thousands, except per kWh amounts):

				Estimated Average
	2011			2012				2013 -2016
Annual Capacity Acquired		143.8			152.8		(a)
Minimum Energy Purchase - annual load factor (b)		75	%		75	%		75	%

Energy Charge	$	29,786		$	33,540		$	20,032
Capacity Charge		32,147			33,570			19,886
Total Energy and Capacity Charge	$	61,933		$	67,110		$	39,918

Average Cost per kWh	$	0.070		$	0.067		$	0.069

(a)

Annual capacity acquired is projected to average approximately 116 MW for 2013 - 2014, 100 MW for 2015 and 19 MW for 2016.

(b)

Annual load factor applies to 12-month periods beginning November 1. Calendar-year load factors may be different.

Independent Power Producers: We receive power from several IPPs, primarily so-called small power producers. These plants use water or biomass as fuel. Most of the power comes through a state-appointed purchasing agent that allocates power to all Vermont utilities under PSB rules. Starting in 2012, we will also purchase power from some larger independent producers, primarily wind projects. Estimated annual purchases are expected to increase from $23.5 million in 2011 to about $35 million in 2012 and up to $47 million by 2016. These cost estimates are based on assumptions regarding the number, sizes and types of IPPs that we purchase from, hydrological and wind conditions and other factors, so actual amounts could be higher or lower. Our total purchases from IPPs were $23.5 million in 2011, $22.9 million in 2010 and $22.6 million in 2009.

Joint-ownership We have joint-ownership interests in electric generating and transmission facilities that are included in Utility Plant on our Consolidated Balance Sheets. These include:

	Fuel Type	Ownership	Date In Service	MW Entitlement
Wyman #4	Oil	1.78%	1978	10.8
Joseph C. McNeil	Various	20.00%	1984	10.8
Millstone Unit #3	Nuclear	1.73%	1986	21.4
Highgate Transmission Facility		47.52%	1985	N/A

At December 31 our share of these facilities was (dollars in thousands):

	2011
	Gross		Accumulated		Net		Plant Under
	Investment		Depreciation		Investment		Construction
Wyman #4	$	3,876	$	3,231	$	644	$	32
Joseph C. McNeil		18,521		14,076		4,445		3
Millstone Unit #3		79,027		43,146		35,881		1,441
Highgate Transmission Facility		14,577		9,388		5,189		4,087
	$	116,001	$	69,841	$	46,159	$	5,563

	2010
	Gross		Accumulated		Net		Plant Under
	Investment		Depreciation		Investment		Construction
Wyman #4	$	3,853	$	3,121	$	732	$	32
Joseph C. McNeil		18,270		13,458		4,812		47
Millstone Unit #3		78,929		42,213		36,716		1,333
Highgate Transmission Facility		14,696		9,438		5,258		12
	$	115,748	$	68,230	$	47,518	$	1,424

Our share of operating expenses for these facilities is included in the corresponding operating accounts on the Consolidated Statements of Income. Each participant in these facilities must provide for its financing.

We have a 1.7303 joint-ownership percentage in Millstone Unit #3, in which DNC is the lead owner with 93.4707 percent of the plant joint-ownership. In January 2004 DNC filed, on behalf of itself and the two minority owners, including us, a lawsuit against the DOE seeking recovery of costs related to the storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. A trial commenced in May 2008. On October 15, 2008, the United States Court of Federal Claims issued a favorable decision in the case, including damages specific to Millstone Unit #3. The DOE appealed the court's decision in December 2008. On February 20, 2009, the government filed a motion seeking an indefinite stay of the briefing schedule. On March 18, 2009, the court granted the government's request to stay the appeal. On November 19, 2009, DNC filed a motion to lift the stay. On April 12, 2010, the stay was lifted and a staggered briefing schedule was proposed, to which DNC has responded with a request to expedite the briefing schedule so that the appeals of all parties can be heard concurrently.

On June 30, 2010, the DOE filed its initial brief in the spent fuel damages litigation. This brief focuses on the costs awarded in connection with Millstone Unit #3. DNC replied to the government's brief in August, 2010. The government's reply brief was filed September 14, 2010 and briefing on the appeal is now complete. Oral argument on the government's appeal occurred before the Federal Circuit on January 12, 2011.

On April 25, 2011 the U.S. Court of Appeals for the Federal Circuit issued a decision affirming the spent fuel damages award for damages incurred through June 30, 2006 in connection with DOE's failure to begin accepting spent fuel for disposal. The government had the option to seek rehearing of the Federal Circuit decision and to seek review by the U.S. Supreme Court. The time period for seeking rehearing was 45 days.

On June 30, 2011, DNC informed us that the DOE decided not to seek rehearing and instead wishes to pay the awarded damages. In October 2011 we received $0.2 million and the amount was credited to our retail customers.

Future Power AgreementsNew Hydro-QuébecAgreement: On August 12, 2010 we, along with GMP, VPPSA, Vermont Electric Cooperative, Inc., Vermont Marble, Town of Stowe Electric Department, City of Burlington, Vermont Electric Department, Washington Electric Cooperative, Inc. and the 13 municipal members of VPPSA (collectively, the “Buyers”) entered into an agreement for the purchase of shares of 218 MW to 225 MW of energy and environmental attributes from HQUS commencing on November 1, 2012 and continuing through 2038.

The rights and obligations of the Buyers under the HQUS PPA, including payment of the contract price and indemnification obligations, are several and not joint or joint and several. Therefore, we shall have no responsibility for the obligations, financial or otherwise, of any other party to the HQUS PPA. The parties have also entered into related agreements, including collateral agreements between each Buyer and HQUS, a Hydro-Québec guaranty, an allocation agreement among the Buyers, and an assignment and assumption agreement between us and Vermont Marble, related to the acquisition.

The HQUS PPA will replace approximately 65 percent of the existing VJO power contract discussed above, which along with the VY PPA supply the majority of Vermont's current power needs. The VJO power contract and the VY PPA expire within the next several years.

On August 17, 2010, the Buyers filed a petition with the PSB asking for Certificates of Public Good under Section 248 of Title 30, Vermont Statutes Annotated. Technical hearings were held and final legal briefs were filed in the first quarter of 2011. On April 15, 2011, the PSB issued an order approving the HQUS PPA.

Under the HQUS PPA, we are entitled to purchase an energy quantity of up to 5 MW from November 1, 2012 to October 31, 2015; 90.4 MW from November 1, 2015 to October 31, 2016; 101.4 MW from November 1, 2016 to October 31, 2020; 103.4 MW from November 1, 2020 to October 31, 2030; 112.8 MW from November 1, 2030 to October 31, 2035; and 27.4 MW from November 1, 2035 to October 31, 2038. These quantities include assumption of Vermont Marble's allocations as a result of our September 1, 2011 purchase of Vermont Marble.

Other Future Power Agreements: As we continue to build and diversify our power portfolio as planned and to comply with state law which establishes goals for including renewable power in our mix, we have signed several agreements for clean and competitively priced renewable energy. On September 9, 2010 we agreed to terms for purchasing output over nine years from Iberdrola Renewables' planned Deerfield Wind Project. The agreement was signed by the parties on December 13, 2010. The project has experienced delays in receiving a necessary permit from the U.S. Forest Service and construction is not now scheduled to take place in a manner that would be sufficient for meeting the conditions precedent of the agreement. The developer received the permit, but it was too late for completion of the project in 2012, and the project is now on hold.

Conditions precedent not satisfied or waived on or before April 1, 2012 could result in termination of the contract by June 30, 2012. We are currently in discussions with Iberdrola, the parent company, with respect to terminating, reforming or replacing the agreement.

Other agreements signed in 2010 include: two separate agreements to purchase 30.3 percent of the actual output from Granite Reliable Wind project for 20 years beginning April 1, 2012 and an additional 20 percent for 15 years beginning in November 2012; an agreement to purchase the entire 4.99 MW output of Ampersand Gilman Hydro for five years starting April 1, 2012; and 15 MW of around-the-clock energy from J.P. Morgan Ventures Energy for the calendar years 2013 through 2015.

On July 27, 2011, in cooperation with an energy management firm, we conducted a highly structured Internet auction that involved a dozen pre-screened northeastern generators and energy marketers. When the bidding closed, we signed three contracts with an average price of approximately $47.50 per megawatt-hour, or 4.75 cents per kilowatt-hour.

Two of the contracts will fill the 2012 gap in our portfolio created by the end of our existing contract with Vermont Yankee. One will supply energy 24 hours per day from April 1, 2012 through the end of the year, while the other will provide both peak and off-peak power during specific periods in 2012 when we have remaining supply gaps. The third contract filled our energy needs during the planned Vermont Yankee refueling outage that ended November 3, 2011.

These purchase contracts will provide about 570,000 megawatt-hours of energy or about 20 percent of our power supply during the life of the contracts, for $27 million. The contracts are for so-called “system power,” meaning they are not conditioned on the operation of individual power generation sources.

In September 2011, we also used the auction process to sell small amounts of projected excess energy to hedge price risks during the first two months of 2012.

Nuclear Decommissioning Obligations We are obligated to pay our share of nuclear decommissioning costs for nuclear plants in which we have an ownership interest. We have an external trust dedicated to funding our joint-ownership share of future Millstone Unit #3 decommissioning costs. DNC has suspended contributions to the Millstone Unit #3 Trust Fund because the minimum NRC funding requirements have been met or exceeded. We have also suspended contributions to the Trust Fund, but could choose to renew funding at our own discretion as long as the minimum requirement is met or exceeded. If a need for additional decommissioning funding is necessary, we will be obligated to resume contributions to the Trust Fund.

We have equity ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic. These plants are permanently shut down and completely decommissioned except for the spent fuel storage at each location. Our obligations related to these plants are described in Note 4 - Investments in Affiliates.

We also had a 35 percent ownership interest in the Vermont Yankee nuclear power plant through our equity investment in VYNPC, but the plant was sold in 2002. Our obligation for plant decommissioning costs ended when the plant was sold, except that VYNPC retained responsibility for the pre-1983 spent fuel disposal cost liability. VYNPC has a dedicated Trust Fund that meets most of the liability. Changes in the underlying interest rates that affect the earnings and the liability could cause the balance to be a surplus or deficit. Excess funds, if any, will be returned to us and the other former owners and must be applied to the benefit of retail customers.

Nuclear Insurance The Price-Anderson Act provides a framework for immediate, no-fault insurance coverage for the public in the event of a nuclear power plant accident that is deemed an “extraordinary nuclear occurrence” by the NRC. The EPACT reinstated and extended the Price-Anderson Act for 20 years. There are two levels of coverage. The primary level provides liability insurance coverage of $375 million, or the maximum private insurance available. If this amount is not sufficient to cover claims arising from an accident, the second level applies offering additional coverage up to $12.6 billion per incident. For the second level, each operating nuclear plant must pay a retrospective premium equal to its proportionate share of the excess loss, up to a maximum of $111.9 million per reactor per incident, limited to a maximum annual payout of $17.5 million per reactor. These assessments will be adjusted for inflation and U.S. Congress can modify or increase the insurance liability coverage limits at any time through legislation. Currently, based on our joint-ownership interest in Millstone Unit #3, we could become liable for about $0.3 million of such maximum assessment per incident per year. Maine Yankee, Connecticut Yankee and Yankee Atomic maintain $100 million in Nuclear Liability Insurance, but have received exemptions from participating in the secondary financial protection program.

Performance Assurance We are subject to performance assurance requirements through ISO-NE under the Financial Assurance Policy for NEPOOL members. At our current investment-grade credit rating, we have a credit limit of $3 million with ISO-NE. We are required to post collateral for all net power and transmission transactions in excess of this credit limit. Additionally, we are currently selling power in the wholesale market pursuant to contracts with third parties, and are required to post collateral under certain conditions defined in the contracts.

At December 31, 2011, we had posted $3.9 million of collateral under performance assurance requirements for certain of our power and transmission transactions, $3.5 million of which was represented by a letter of credit and $0.4 million of which was represented by cash and cash equivalents. At December 31, 2010, we had posted $6.6 million of collateral under performance assurance requirements for certain of our power and transmission transactions, $5.5 million of which was represented by a letter of credit and $1.1 million of which was represented by cash and cash equivalents.

We are also subject to performance assurance requirements under our Vermont Yankee power purchase contract (the 2001 Amendatory Agreement). If Entergy-Vermont Yankee, the seller, has commercially reasonable grounds to question our ability to pay for our monthly power purchases, Entergy-Vermont Yankee may ask VYNPC and VYNPC may then ask us to provide adequate financial assurance of payment. We have not had to post collateral under this contract.

Environmental Over the years, more than 100 companies have merged into or been acquired by CVPS. At least two of those companies used coal to produce gas for retail sale. Gas manufacturers, their predecessors and CVPS used waste disposal methods that were legal and acceptable then, but may not meet modern environmental standards and could represent a liability. These practices ended more than 50 years ago. Some operations and activities are inspected and supervised by federal and state authorities, including the EPA. We believe that we are in compliance with all laws and regulations and have implemented procedures and controls to assess and assure compliance. Corrective action is taken when necessary.

As of December 31, 2011, our Environmental Reserve was $0.3 million, compared to $0.8 million in 2010 and $1.6 million in 2009. A summary of the Environmental Reserve as of December 31 follows (dollars in thousands):

	2011			2010			2009
Environmental reserve balance at beginning of year	$	836		$	1,565		$	1,732
Charged to income and expenses		317			838
Deductions		(805	)		(1,567	)		(167	)
Environmental reserve balance at end of year	$	348		$	836		$	1,565

The reserve for environmental matters is included in current liabilities on the Consolidated Balance Sheets and represents our best estimate of the cost to remedy issues at these sites based on available information as of the end of the applicable reporting periods. Below is a brief discussion of the significant sites for which we have recorded reserves.

Cleveland Avenue Property: The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal. Later, we sited various operations there. Due to the existence of coal tar deposits, PCB contamination and the potential for off-site migration, we conducted studies in the late 1980s and early 1990s to quantify the nature and extent of contamination and potential costs to remediate the site. Investigation at the site continued, including work with the State of Vermont to develop a mutually acceptable solution. In June 2010, both the VANR and the EPA approved separate remediation work plans for the manufactured gas plant and PCB waste at the site. Remedial work started in August 2010 and concluded in early December 2010. It was necessary to increase the reserve by $0.3 million in the first quarter of 2011. In February 2011, we submitted a Construction Completion Report for the project to the EPA and VANR for review. The report documented remedial construction and confirmatory sampling activities. Some additional site work, including final grading and vegetation planting, occurred during the third quarter of 2011, and the site sustained some minor flood damage from Tropical Storm Irene. As of December 31, 2011, there was no remaining obligation.

Brattleboro Manufactured Gas Facility: In the 1940s, we owned and operated a manufactured gas facility in Brattleboro, Vermont. We ordered a site assessment in 1999 at the request of the State of New Hampshire. In 2001, New Hampshire indicated that no further action was required, although it reserved the right to require further investigation or remedial measures. In 2002, the VANR notified us that our corrective action plan for the site was approved. As of December 31, 2011, our estimate of the remaining obligation is $0.3 million.

The Windham Regional Commission and the Town of Brattleboro are currently pursuing the redevelopment of the gas plant site and waterfront area into vehicle parking with green space. This concept calls for the removal of the remnant gas plant building plus covering and otherwise avoiding contaminated areas instead of removing contaminated soil and debris.

Throughout 2010, we discussed the proposed redevelopment with consultants for the Town of Brattleboro and the Windham Regional Commission. We expressed a willingness to enter into a formal remediation agreement with the Town of Brattleboro governing the redevelopment of the site.

We met with the Town of Brattleboro in 2011 and we agreed to an Amended and Restated Grant of Environmental Restrictions for the gas plant property. In November 2011, we contributed $0.2 million toward the remediation project. We will monitor site remediation and construction in 2012 and reassess the reserve to determine if an adjustment is necessary.

Dover, New Hampshire, Manufactured Gas Facility: In 1999, PSNH contacted us about this site. PSNH alleged that we were partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric, which merged into CVPS on the same day that PSNH bought the facility. In 2002, we reached a settlement with PSNH in which certain liabilities we might have had were assigned to PSNH in return for a cash settlement we paid over time based on completion of PSNH's cleanup effort and periodic monitoring. In December 2011, we made the final settlement payment. As of December 31, 2011, there was no remaining obligation.

Middlebury Lower Substation: By letter dated February 5, 2010, the VANR Sites Management Section informed us they require additional investigation of the soil contamination at the Middlebury Lower Substation. This was a result of voluntarily submitted information from internal soil sampling that we completed in the fall of 2009. The soil sampling showed elevated levels of TPH that required remediation. The contaminated soil and concrete was removed in conjunction with the reconstruction of the substation in 2011. As of December 31, 2011, there was no remaining obligation.

Salisbury Substation: We completed internal testing and found PCBs and TPH, in addition to small quantities of pesticides in the soil and concrete at this site. The substation is located adjacent to the Salisbury hydroelectric power station. It is scheduled to be retired and replaced during 2011. Final results indicated that PCB, TPH and pesticide concentrations exceed state and federal regulatory limits on portions at the site. In late 2011 and early 2012, we removed the contaminated material from the site in accordance with VT ANR and EPA-approved remediation plans. We submitted a letter to the VANR Sites Management Section proposing that PCB remediation efforts would be sufficient mitigation for TPH and pesticide contamination, and proposed to collect soil samples for confirmatory testing of these compounds. As of December 31, 2011, our estimate of the remaining obligation is less than $0.1 million.

To management's knowledge, there is no pending or threatened litigation regarding other sites with the potential to cause material expense. No government agency has sought funds from us for any other study or remediation.

Catamount Indemnifications On December 20, 2005, we completed the sale of Catamount, our wholly owned subsidiary, to CEC Wind Acquisition, LLC, a company established by Diamond Castle Holdings, a New York-based private equity investment firm. Under the terms of the agreements with Catamount and Diamond Castle Holdings, we agreed to indemnify them, and certain of their respective affiliates, in respect of a breach of certain representations and warranties and covenants, most of which ended June 30, 2007, except certain items that customarily survive indefinitely. Indemnification is subject to a $1.5 million deductible and a $15 million cap, excluding certain customary items. Environmental representations are subject to the deductible and the cap, and such environmental representations for only two of Catamount's underlying energy projects survived beyond June 30, 2007. Our estimated “maximum potential” amount of future payments related to these indemnifications is limited to $15 million. We have not recorded any liability related to these indemnifications. To management's knowledge, there is no pending or threatened litigation with the potential to cause material expense. No government agency has sought funds from us for any study or remediation.

Leases and support agreements Capital Leases: We had obligations under capital leases of $3.4 million at December 31, 2011 and $4.4 million at December 31, 2010. The current and long-term portions are included as liabilities on the Consolidated Balance Sheets, and are offset by Property Under Capital Leases included in Utility plant. We account for capital leases under FASB's guidance for leases. In accordance with FASB's guidance for regulated operations and based on our ratemaking treatment, amortizations of leased assets are recorded as operating expenses on the Statement of Operations, depending on the nature and function of the leased assets. Of the $3.4 million in 2011, $3.3 million is related to the Hydro-Québec Phase II transmission facilities and the remaining $0.1 million is related to several five-year office and computing equipment leases.

We participated with other electric utilities in the construction of the Phase II transmission facilities in New England, which were completed at a total initial cost of $487 million. Under a 30-year support agreement relating to participation in the facilities, we agreed to pay our 5.132 percent share of Phase II costs, including capital costs plus the costs of owning and operating the facilities, over a 25-year recovery period that ends in 2015, plus operating and maintenance expenses for the life of the agreement, in exchange for the rights to use a similar share of the available transmission capacity through 2020. Approximately $33 million of additional investments have been made to the Phase II transmission facilities since they were initially constructed. All costs under these agreements are recorded as transmission expense in accordance with our ratemaking policies. At December 31, 2011, the $3.3 million unamortized balance was comprised of $19.2 million related to our share of original costs and additional investments, offset by $15.9 million of accumulated amortization.

We also participated with other electric utilities in the construction of the Hydro-Québec Phase I transmission facilities in northeastern Vermont and northern New Hampshire, which were completed at a total cost of $140 million. Under the 30-year support agreement relating to participation in the facilities, we were obligated to pay our 4.55 percent share of Phase I capital costs over a 20-year recovery period that ended in 2006, plus operating and maintenance expenses for the life of the agreement, in exchange for the rights to use a similar share of the available transmission capacity through 2016. At December 31, 2011, we had recorded accumulated amortization of $4.9 million representing our share of the original costs associated with the Phase I transmission facility. Our Phase I share increased to 4.66 percent effective September 1, 2011 due to the purchase of Vermont Marble.

The Phase I and Phase II support agreements provide options for extending the agreements an additional 20 years. Each option must be exercised two years before each agreement terminates, and the transmission facilities for Phase I and Phase II must operate simultaneously for the interconnection to operate, therefore both agreements would need to be extended to be operative. Future annual payments relating to the Phase I and Phase II transmission facilities are expected to decline from $3 million in 2012 to $2.3 million in 2016. If we elect to extend both agreements, annual payments are generally expected to continue declining past the 2020 renewal year, unless unforeseen equipment failures occur. Approximately $0.5 million of the annual costs are currently reimbursed to us pursuant to the ISO-NE Open Access Transmission Tariff.

For the year ended December 31, 2011, imputed interest on capital leases totaled $0.3 million. A summary of minimum lease payments as of December 31, 2011 follows (dollars in thousands).

Year	Capital Leases
2012	$	1,171
2013		1,085
2014		954
2015		738
2016		0
Future minimum lease payments		3,948
Less: amount representing interest		(560	)
Present value of net minimum lease payments	$	3,388

Operating Leases: We have two master lease agreements for vehicles and related equipment. On October 30, 2009, we signed a vehicle lease agreement to finance many of the vehicles covered by a former agreement. Our guarantee obligation under this lease will not exceed 8 percent of the acquisition cost. The maximum amount of future payments under this guarantee at December 31, 2011 is approximately $0.3 million. The total future minimum lease payments required for all lease schedules under this agreement at December 31, 2011 is $2.2 million. As of December 31, 2011 there is no credit line in place for additions under this agreement. The total acquisition cost of all lease additions under this agreement at December 31, 2011 was $4.1 million. At December 31, 2010, the total acquisition cost of all lease additions under this agreement was $5.3 million.

On October 24, 2008, we entered into an operating lease for new vehicles and other related equipment. Our guarantee obligation under this lease is limited to 5 percent of the acquisition cost. The maximum amount of future payments under this guarantee is approximately $0.1 million. The total future minimum lease payments required for all lease schedules under this agreement at December 31, 2011 is $1.7 million. As of December 31, 2011 there is no credit line in place for additions under this agreement. The total acquisition cost of all lease additions under this agreement at December 31, 2011 and 2010 was $2.9 million.

Other operating lease commitments are considered minimal, as most are cancelable after one year from inception or the future minimum lease payments are of a nominal amount.

At December 31, 2011, future minimum rental payments required under non-cancelable operating leases are expected to total $3.6 million, consisting of $1.4 million in 2012, $1.2 million in 2013, $0.7 million in 2014, $0.3 million in 2015, and $0 million thereafter.

Total rental expense, which includes pole attachment rents in addition to the operating lease agreements described above, amounted to $6.1 million in 2011 and 2010 and $6.3 million in 2009. These are included in Other operation on the Consolidated Statements of Income.

Merger Agreement with Gaz Métro The Merger Agreement contains certain termination rights for both CVPS and

Gaz Métro and further provides that upon termination of the merger agreement under specified circumstances, CVPS may be required to pay Gaz Métro a termination fee of $17.5 million and reimburse Gaz Métro for up to $2 million of its reasonable out-of-pocket transaction expenses. Also, see Note 2 - Summary of Significant Accounting Policies to the accompanying Notes to Consolidated Financial Statements.

Reserve for Loss on Power Contract In 2004, we established a reserve for a loss on a terminated power sales agreement in connection with the sale of a subsidiary's franchise. The reserve is being amortized on a straight-line basis through 2015 as the cash is paid out under the underlying supply contracts. The amortization is being credited to purchased power expense on the Consolidated Statement of Income. The balance of the reserve was $4.8 million in December 31, 2011 and $6 million at December 31, 2010. The current and long-term portions are included as liabilities on the Consolidated Balance Sheets.

Customer Bankruptcy On October 26, 2009, a large customer filed for bankruptcy protection. In December 2010, the PSB approved the final bankruptcy plan and in January 2011, the court approved the plan and final settlement. As of December 31, 2010, we reversed the reserve of $1.1 million that was previously recorded in 2009 and received payment in January 2011.

Legal Proceedings We are involved in legal and administrative proceedings, including civil litigation, in the normal course of business as well as a number of lawsuits relating to our pending merger agreement with Gaz Métro that are described in Note 1 – Business Organization, Litigation Related to Merger Agreement. We are unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs or legal liabilities that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, we do not believe that it is probable that any such legal liability will have a material impact on our consolidated financial position. It is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on our results of operations, financial condition or cash flows.

Appropriated Retained Earnings Major hydroelectric project licenses provide that after an initial 20-year period, a portion of the earnings of such project in excess of a specified rate of return is to be set aside in appropriated retained earnings in compliance with FERC Order No. 5, issued in 1978. Appropriated retained earnings included in retained earnings on the Consolidated Balance Sheets were $0.8 at December 31, 2011 and December 31, 2010.