COMMITMENTS AND CONTINGENCIES	3 Months Ended
Mar. 31, 2011
COMMITMENTS AND CONTINGENCIES [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 13 - 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. See Note 4 – Investments in Affiliates for additional information on the VY PPA. 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 $17.1 million for the second quarter and $34.2 million for the six months ended June 30, 2011 and $10.2 million for the second quarter and $26.4 million for the six months ended June 30, 2010. On June 22, 2010, we, along with GMP, made a claim under the September 6, 2001 VY PPA. The claim is 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. 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. Our contract for power purchases from VYNPC ends in March 2012, but there is a risk that we could lose this resource if the plant shuts down for any reason before that date, and its future beyond that date is uncertain. An early shutdown could cause our customers to lose the economic benefit of an energy volume of close to 50 percent of our total committed supply and we would have to acquire replacement power resources for approximately 40 percent of our estimated power supply needs. While this has been a significant concern in the past, the ever-shortening 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 capacity, and due to significant reductions in natural gas prices, electrical energy is available at competitive rates. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB would allow timely and full recovery of any costs related to such shutdown. Under Vermont law, in addition to a favorable Vermont legislative vote, the PSB must issue a Certificate of Public Good in order for the plant to continue to operate 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. On November 2, 2010 Vermont elected a new governor who continues to strongly advocate for the closure of the Vermont Yankee plant when its current license expires. After the November election, Entergy announced it had begun pursuing a possible sale of the plant, apparently concluding that the plant had a better chance at remaining part of Vermont's power supply under new ownership. We vigorously engaged in contract talks with Entergy-Vermont Yankee for the specific purpose of increasing the chances the plant would continue to operate beyond 2012. On March 29, 2011, Entergy announced its sale process had concluded unsuccessfully. Consequently, the potential for state legislative and regulatory approval of continued plant operations is now, in our view, extremely low. However, as discussed more fully below, Entergy-Vermont Yankee is seeking to operate the plant beyond March 21, 2012 without such approvals. On March 10, 2011, the NRC voted 4-0 to approve the 20-year license extension through March 21, 2032 requested by Entergy-Vermont Yankee. This approval removes the last federal-level regulatory requirement for relicensing of the Vermont Yankee station. Entergy-Vermont Yankee, previously attempting to overcome legislative concerns, challenged the state's authority as it relates to relicensing. In a federal lawsuit filed on April 18, 2011, Entergy-Vermont Yankee contended that the state was improperly attempting to interfere with its relicensing. In the complaint filed in U.S. District Court for the District of Vermont, Entergy-Vermont Yankee is seeking 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 seeks both declaratory and injunctive relief, and contends 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. The state of Vermont has vigorously defended its position. On June 27, 2011, ISO-NE announced that studies have shown Vermont Yankee is “needed to support the grid's ability to reliably meet demand in Vermont, southern New Hampshire and portions of Massachusetts, as well as reliability for the entire region's power system.” On July 18, 2011, the federal district court denied Entergy-Vermont Yankee's motion for a preliminary injunction to enjoin the state from enforcing Vermont statutes that would require Vermont Yankee to cease operations after March 21, 2012. In denying the motion, the court expressly declined to issue a holding regarding Entergy's likelihood of success on the merits but noted that Entergy raised serious questions regarding its Atomic Energy Act preemption claim, which warrant further briefing and a “full-dress” trial on the merits. The court scheduled a trial on the merits for September 12, 2011. The court also took judicial notice that on June 28, 2011, Standard & Poor's affirmed Entergy Corporation's corporate credit and issue ratings but revised its credit outlook from “stable” to “negative.” On July 25, 2011, Entergy announced that its board of directors approved the refueling scheduled for October 2011, despite uncertainty about whether the Vermont Yankee plant will continue operations after March 21, 2012. We have purchased replacement power for this expected outage as discussed below in Future Power Agreements. We are evaluating the potential impact of the litigation on our financial statements and on our customers. The outcome of this matter is uncertain at this time. Hydro-Québec: We are purchasing power from Hydro-Québec under the 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 19 percent after 2012, and by approximately 84 percent after 2015. Our total purchases under the VJO Power contract were $14.7 million for the first quarter and $31.2 million for the six months ended June 30, 2011 and $15.1 million for the first quarter and $31.7 million for the six months ended June 30, 2010 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 June 30, 2011, our obligation is about 47 percent of the total VJO power contract through 2016, and represents approximately $254.5 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 $299.1 million for the remainder of the contract, assuming that all members of the VJO defaulted by July 1, 2011 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. Independent Power Producers: We receive power from several IPPs. 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. Our total purchases from IPPs were $6.9 million for the second quarter and $13.2 million for the first six months of 2011 and $5.8 million for the second quarter and $12.2 million for the first six months of 2010. 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. DOE Litigation 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. A formal request to the DOE for payment has been made. Payment is anticipated by the end of the third quarter. Our share is approximately $0.2 million and will be credited to our retail customers. We continue to pay our share of the DOE Spent Fuel assessment expenses levied on actual generation. 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 pending 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. The obligations of HQUS and each Buyer are contingent upon the receipt of certain governmental approvals. 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, which we plan to execute as proposed. In the event the HQUS PPA is terminated with respect to any Buyer as a result of such Buyer's failure to receive governmental approvals, each of the other Buyers will have an option to purchase the additional energy. Under the Agreement, subject to regulatory approval, we would be entitled to purchase an energy quantity of up to 85.4 MW from November 1, 2015 to October 31, 2016; 96.4 MW from November 1, 2016 to October 31, 2020; 98.4 MW from November 1, 2020 to October 31, 2030; 112.1 MW from November 1, 2030 to October 31, 2035; and 26.7 MW from November 1, 2035 to October 31, 2038. Other Future Power Agreements: On July 27, 2011, in cooperation with an energy management firm, we conducted a highly structured Internet auction that involved a dozen pre-screened north-eastern 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 when we had remaining supply gaps next year. The third contract will fill our energy needs during the planned Vermont Yankee refueling outage in October 2011. The 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. 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 $3.4 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 June 30, 2011, we had posted $4.8 million of collateral under performance assurance requirements for certain of our power and transmission transactions, $4.5 million of which was represented by a letter of credit and $0.3 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. The total reserve for environmental matters was $0.8 million as of June 30, 2011 and December 31, 2010. The reserve for environmental matters is included as current and long-term liabilities on the Condensed 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 sitework including final grading and vegetation planting is ongoing. As of June 30, 2011, our estimate of the remaining obligation is less than $0.1 million. 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 June 30, 2011, our estimate of the remaining obligation is $0.5 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. In 2010, we discussed the proposed redevelopment with consultants for the Town of Brattleboro and the Windham Regional Commission. We have expressed our willingness to enter into a formal remediation agreement with the Town of Brattleboro governing the redevelopment to assure continued acknowledgement of site contamination. We received a non-binding letter from the Town of Brattleboro summarizing its preferred remedial plan. We met with the Town of Brattleboro in June 2011 and learned they expect to complete the gas plant site and waterfront project in 2011. We expect to enter into an agreement to participate in the project. Subsequently, we will reassess the reserve and need, if any, for a revised probabilistic cost estimate for site remediation. 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 based on completion of PSNH's cleanup effort. As of June 30, 2011, our estimate of the remaining obligation is less than $0.1 million. 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. Most of the soil removal has already occurred and the remaining contaminated material is being removed in conjunction with completion of the substation reconstruction. As of June 30, 2011, our estimate of the remaining obligation is less than $0.1 million. 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 at portions at the site. 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. Remediation is expected to begin during the third or fourth quarter of 2011. As of June 30, 2011, our estimate of the remaining obligation is $0.2 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 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 June 30, 2011 is approximately $0.4 million. The total future minimum lease payments required for all lease schedules under this agreement at June 30, 2011 is $3 million. As of June 30, 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 June 30, 2011 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 June 30, 2011 is $1.9 million. As of June 30, 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 June 30, 2011 was $2.9 million. 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. 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 Metro 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.

NOTE 13 - 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. See Note 4 – Investments in Affiliates for additional information on the VY PPA.

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 $17.1 million for the second quarter and $34.2 million for the six months ended June 30, 2011 and $10.2 million for the second quarter and $26.4 million for the six months ended June 30, 2010.

On June 22, 2010, we, along with GMP, made a claim under the September 6, 2001 VY PPA. The claim is 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. 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.

Our contract for power purchases from VYNPC ends in March 2012, but there is a risk that we could lose this resource if the plant shuts down for any reason before that date, and its future beyond that date is uncertain. An early shutdown could cause our customers to lose the economic benefit of an energy volume of close to 50 percent of our total committed supply and we would have to acquire replacement power resources for approximately 40 percent of our estimated power supply needs. While this has been a significant concern in the past, the ever-shortening 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 capacity, and due to significant reductions in natural gas prices, electrical energy is available at competitive rates. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB would allow timely and full recovery of any costs related to such shutdown.

Under Vermont law, in addition to a favorable Vermont legislative vote, the PSB must issue a Certificate of Public Good in order for the plant to continue to operate 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. On November 2, 2010 Vermont elected a new governor who continues to strongly advocate for the closure of the Vermont Yankee plant when its current license expires.

After the November election, Entergy announced it had begun pursuing a possible sale of the plant, apparently concluding that the plant had a better chance at remaining part of Vermont's power supply under new ownership. We vigorously engaged in contract talks with Entergy-Vermont Yankee for the specific purpose of increasing the chances the plant would continue to operate beyond 2012. On March 29, 2011, Entergy announced its sale process had concluded unsuccessfully. Consequently, the potential for state legislative and regulatory approval of continued plant operations is now, in our view, extremely low. However, as discussed more fully below, Entergy-Vermont Yankee is seeking to operate the plant beyond March 21, 2012 without such approvals.

On March 10, 2011, the NRC voted 4-0 to approve the 20-year license extension through March 21, 2032 requested by Entergy-Vermont Yankee. This approval removes the last federal-level regulatory requirement for relicensing of the Vermont Yankee station.

Entergy-Vermont Yankee, previously attempting to overcome legislative concerns, challenged the state's authority as it relates to relicensing. In a federal lawsuit filed on April 18, 2011, Entergy-Vermont Yankee contended that the state was improperly attempting to interfere with its relicensing. In the complaint filed in U.S. District Court for the District of Vermont, Entergy-Vermont Yankee is seeking 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 seeks both declaratory and injunctive relief, and contends 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. The state of Vermont has vigorously defended its position.

On June 27, 2011, ISO-NE announced that studies have shown Vermont Yankee is “needed to support the grid's ability to reliably meet demand in Vermont, southern New Hampshire and portions of Massachusetts, as well as reliability for the entire region's power system.”

On July 18, 2011, the federal district court denied Entergy-Vermont Yankee's motion for a preliminary injunction to enjoin the state from enforcing Vermont statutes that would require Vermont Yankee to cease operations after March 21, 2012. In denying the motion, the court expressly declined to issue a holding regarding Entergy's likelihood of success on the merits but noted that Entergy raised serious questions regarding its Atomic Energy Act preemption claim, which warrant further briefing and a “full-dress” trial on the merits. The court scheduled a trial on the merits for September 12, 2011. The court also took judicial notice that on June 28, 2011, Standard & Poor's affirmed Entergy Corporation's corporate credit and issue ratings but revised its credit outlook from “stable” to “negative.”

On July 25, 2011, Entergy announced that its board of directors approved the refueling scheduled for October 2011, despite uncertainty about whether the Vermont Yankee plant will continue operations after March 21, 2012. We have purchased replacement power for this expected outage as discussed below in Future Power Agreements.

We are evaluating the potential impact of the litigation on our financial statements and on our customers. The outcome of this matter is uncertain at this time.

Hydro-Québec: We are purchasing power from Hydro-Québec under the 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 19 percent after 2012, and by approximately 84 percent after 2015. Our total purchases under the VJO Power contract were $14.7 million for the first quarter and $31.2 million for the six months ended June 30, 2011 and $15.1 million for the first quarter and $31.7 million for the six months ended June 30, 2010

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 June 30, 2011, our obligation is about 47 percent of the total VJO power contract through 2016, and represents approximately $254.5 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 $299.1 million for the remainder of the contract, assuming that all members of the VJO defaulted by July 1, 2011 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.

Independent Power Producers: We receive power from several IPPs. 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. Our total purchases from IPPs were $6.9 million for the second quarter and $13.2 million for the first six months of 2011 and $5.8 million for the second quarter and $12.2 million for the first six months of 2010.

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.

DOE Litigation 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. A formal request to the DOE for payment has been made. Payment is anticipated by the end of the third quarter. Our share is approximately $0.2 million and will be credited to our retail customers.

We continue to pay our share of the DOE Spent Fuel assessment expenses levied on actual generation.

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 pending 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.

The obligations of HQUS and each Buyer are contingent upon the receipt of certain governmental approvals. 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, which we plan to execute as proposed. In the event the HQUS PPA is terminated with respect to any Buyer as a result of such Buyer's failure to receive governmental approvals, each of the other Buyers will have an option to purchase the additional energy.

Under the Agreement, subject to regulatory approval, we would be entitled to purchase an energy quantity of up to 85.4 MW from November 1, 2015 to October 31, 2016; 96.4 MW from November 1, 2016 to October 31, 2020; 98.4 MW from November 1, 2020 to October 31, 2030; 112.1 MW from November 1, 2030 to October 31, 2035; and 26.7 MW from November 1, 2035 to October 31, 2038.

Other Future Power Agreements: On July 27, 2011, in cooperation with an energy management firm, we conducted a highly structured Internet auction that involved a dozen pre-screened north-eastern 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 when we had remaining supply gaps next year. The third contract will fill our energy needs during the planned Vermont Yankee refueling outage in October 2011.

The 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.

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 $3.4 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 June 30, 2011, we had posted $4.8 million of collateral under performance assurance requirements for certain of our power and transmission transactions, $4.5 million of which was represented by a letter of credit and $0.3 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.

The total reserve for environmental matters was $0.8 million as of June 30, 2011 and December 31, 2010. The reserve for environmental matters is included as current and long-term liabilities on the Condensed 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 sitework including final grading and vegetation planting is ongoing. As of June 30, 2011, our estimate of the remaining obligation is less than $0.1 million.

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 June 30, 2011, our estimate of the remaining obligation is $0.5 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.

In 2010, we discussed the proposed redevelopment with consultants for the Town of Brattleboro and the Windham Regional Commission. We have expressed our willingness to enter into a formal remediation agreement with the Town of Brattleboro governing the redevelopment to assure continued acknowledgement of site contamination. We received a non-binding letter from the Town of Brattleboro summarizing its preferred remedial plan.

We met with the Town of Brattleboro in June 2011 and learned they expect to complete the gas plant site and waterfront project in 2011. We expect to enter into an agreement to participate in the project. Subsequently, we will reassess the reserve and need, if any, for a revised probabilistic cost estimate for site remediation.

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 based on completion of PSNH's cleanup effort. As of June 30, 2011, our estimate of the remaining obligation is less than $0.1 million.

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. Most of the soil removal has already occurred and the remaining contaminated material is being removed in conjunction with completion of the substation reconstruction. As of June 30, 2011, our estimate of the remaining obligation is less than $0.1 million.

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 at portions at the site. 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. Remediation is expected to begin during the third or fourth quarter of 2011. As of June 30, 2011, our estimate of the remaining obligation is $0.2 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 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 June 30, 2011 is approximately $0.4 million. The total future minimum lease payments required for all lease schedules under this agreement at June 30, 2011 is $3 million. As of June 30, 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 June 30, 2011 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 June 30, 2011 is $1.9 million. As of June 30, 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 June 30, 2011 was $2.9 million.

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.

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 Metro 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.