CV Central Vermont Public Service Corp.

In this section we discuss the general financial condition and results of operations for Central Vermont Public Service Corporation (the "Company" or "we" or "our" or "us") and its subsidiaries. Certain factors that may impact future operations are also discussed. Our discussion and analysis is based on, and should be read in conjunction with, the accompanying Condensed Consolidated Financial Statements.

Forward-looking statements  Statements contained in this report that are not historical fact are forward-looking statements within the meaning of the 'safe-harbor' provisions of the Private Securities Litigation Reform Act of 1995. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements. Forward-looking statements involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Actual results will depend upon, among other things:

• the actions of regulatory bodies;
• performance and continued operation of the Vermont Yankee nuclear power plant;
• effects of and changes in weather and economic conditions;
• volatility in wholesale power markets;
• ability to maintain or improve our current credit ratings; and
• other considerations such as the operations of ISO-New England, changes in the cost or availability of capital, authoritative accounting guidance and the effect of the volatility in the equity markets on pension benefit and other costs.

We cannot predict the outcome of any of these matters; accordingly, there can be no assurance as to actual results. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

Our core business is the Vermont electric utility business. We typically generate most of our earnings through retail electricity sales. We also sell excess power, if any, to third parties in New England and to ISO-New England. The resale revenue generated from these sales helps to mitigate our power supply costs, which comprise almost 60 percent of our annual operating expenses. The rates we charge for retail electricity sales are regulated by the Vermont Public Service Board ("PSB"). Fair regulatory treatment is fundamental to maintaining our financial stability. Rates must be set at levels to recover costs, including a market rate of return to equity and debt holders, in order to attract capital.

Our consolidated earnings for the third quarter were $4.3 million or 41 cents per diluted share of common stock, and $10.5 million, or 99 cents per diluted share of common stock for the first nine months of 2007. This compares to consolidated earnings of $7.0 million, or 66 cents per diluted share of common stock for the third quarter, and $12.1 million, or $1.07 per diluted share of common stock for the first nine months of 2006. The primary drivers of the earnings variances for the third quarter and first nine months of 2007 are described in Results of Operations below.

We are continuing to focus on the following strategic financial initiatives:

1. Restoring our corporate credit rating to investment-grade.
2. Ensuring that our retail rates are set at levels to recover our costs of service. In May we filed a request for a 4.46 percent rate increase, and in August we filed an alternative regulation plan proposal for PSB approval. See Retail Rates below.
3. Evaluating financing options so that we can continue to invest in Vermont Transco LLC ("Transco"), which was formed in June 2006 by Vermont Electric Power Company Inc. ("VELCO") and its owners, including us, for construction, maintenance and operation of transmission facilities in Vermont. See Liquidity and Capital Resources.
4. Planning for replacement power when our long-term power contracts with Vermont Yankee Nuclear Power Corporation ("VYNPC") and Hydro-Quebec expire. See Power Supply Matters below.

What follows is a discussion of our results of operations and certain business risks including cash flow risks, regulatory risks and power supply risks.

On December 7, 2006, the PSB issued an Order ("2006 Rate Order") approving a 4.07 percent rate increase effective January 1, 2007. The 2006 Rate Order provided, among other things, an allowed rate of return on common equity of 10.75 percent capped until our next rate proceeding. The rate increase, net of amounts to be returned to customers as described below, will add revenue of approximately $9.9 million annually.

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On January 12, 2007, the PSB issued an Order denying our Accounting Order request for recovery of $1.5 million of incremental replacement power costs associated with a 2005 Vermont Yankee refueling outage. Pursuant to the 2006 Rate Order, because the 4.07 percent rate increase included recovery of the incremental replacement power costs, we began deferring $1.5 million of revenue over two years, and will continue such deferral until our next rate proceeding, at which time the total amount deferred will be returned to customers. As of September 30, 2007, we deferred $0.6 million as a liability with an offsetting reduction in operating revenue.

On May 15, 2007, we filed a request for a 4.46 percent rate increase (additional revenue of about $12.4 million on an annual basis), to be effective February 1, 2008.  Our rate increase request reflects expected increases in operating costs including, among other things, purchased power and transmission costs and increases in return on rate base related to additional investments in our plant and Transco. In October 2007, we entered into settlement discussions with the DPS, including extension of the original schedule for the rate proceeding. We cannot predict the outcome of this rate proceeding or the settlement discussions at this time.

On August 31, 2007, we submitted an alternative regulation plan proposal for PSB approval. If approved, our plan would allow for quarterly rate adjustments to reflect power supply cost changes and annual rate adjustments to reflect changes, within predetermined limits, from our allowed earnings level. The plan is designed to encourage efficiency in operations, and would replace the traditional ratemaking process. We cannot predict the outcome of this matter at this time.

On April 25, 2007, the PSB approved the rate design agreement that we had previously reached with the Vermont Department of Public Service ("DPS"). The rate design became effective for bills rendered on or after July 1, 2007, except for one rate class change with implementation delayed until September 1, 2007. The rate design results in a modest reallocation of revenue by customer class with greater emphasis on energy charges in reaction to wholesale market energy costs. The rate design agreement also included a comprehensive study of the need for new service offerings and further rate redesign given certain fundamental changes in how costs are incurred to serve load based on availability of advanced metering and communications and structural changes in the New England wholesale power market. The study is due to the PSB in April 2008.

Cash Flows At September 30, 2007, we had cash and cash equivalents of $3.6 million included in total working capital of $2.5 million. At September 30, 2006, we had cash and cash equivalents of $3.3 million included in total working capital of $9.8 million. The primary components of cash flows from operating, investing and financing activities for both periods are discussed in more detail below.

Transco Based on current projections, Transco expects to need additional capital over the 2007 to 2010 timeframe, but its projections are subject to change based on a number of factors, including revised construction project estimates, timing of regulatory project approvals, and desired changes in its equity-to-debt ratio. While we have no obligation to make additional investments in Transco, we continue to evaluate investment opportunities on a case-by-case basis. Based on Transco's current projections we could have an opportunity to make additional investments of up to $65.0 million in the fourth quarter of 2007, but the timing and amount depend on Transco's regulatory schedule and the amounts invested by other owners. On October 30, 2007, Transco received PSB approval to issue up to approximately $114.0 million of equity.

We are currently considering issuance of unsecured subordinated debt to fund the fourth quarter 2007 investment, but any investments that we make in Transco are subject to available capital and appropriate regulatory approvals.

Cash Flow Risks We believe that cash on hand, cash flow from operations and our $25.0 million credit facility will be sufficient to fund our business over the next year. Based on our current cash forecasts, we believe the borrowing capacity under the credit facility will provide sufficient liquidity over this time period. However, an extended unplanned Vermont Yankee plant outage or similar event could significantly impact our liquidity due to the potentially high cost of replacement power and performance assurance requirements arising from purchases through ISO-New England or third parties. In the event of an extended Vermont Yankee plant outage, we could seek emergency rate relief from our regulators. Other material risks to cash flow from operations include: loss of retail sales revenue from unusual weather; slower-than-anticipated load growth and unfavorable economic conditions; increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power or an unexpected power source interruption; required prepayments for power purchases; and increases in performance assurance requirements.

Financing
Credit Facility:    We have a three-year $25.0 million unsecured revolving-credit facility with a lending institution pursuant to a Credit Agreement dated October 21, 2005. We make periodic short-term borrowings under the revolving credit facility to manage our working capital requirements. In September, $2.4 million was outstanding under this facility and letters of credit totaling $4.0 million were outstanding under the facility to support certain power-related performance assurance requirements.

Letters of Credit:   In addition to the letters of credit we issued under the credit facility, we have three outstanding secured letters of credit issued by one bank, totaling $16.9 million in support of three separate issues of industrial development revenue bonds totaling $16.3 million. These letters of credit, which expire on November 30, 2007, have been extended by the bank to November 30, 2008. The letters of credit are secured under our first mortgage indenture. At September 30, 2007, there were no amounts drawn under these letters of credit.

Covenants:   At September 30, 2007, we were in compliance with all financial and non-financial covenants related to our various debt agreements, articles of association, letters of credit and credit facility.

Performance Assurance  At September 30, 2007, we had posted $5.2 million of collateral under performance assurance requirements for certain of our power contracts, of which $4.0 million was in the form of letters of credit and the remainder was in cash. We are subject to performance assurance requirements for power purchase and sale transactions through ISO-New England under the Financial Assurance Policy for NEPOOL members. Our credit limit with ISO-New England is zero and we are required to post collateral for all net purchase transactions. We are subject to performance assurance requirements for power purchase and sale transactions through ISO-New York, but activity in this market has been limited. 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.

We are also subject to performance assurance requirements under our Vermont Yankee power purchase contract (the 2001 Amendatory Agreement). If Entergy Nuclear Vermont Yankee, LLC ("ENVY"), the seller, has commercially reasonable grounds to question our ability to pay for monthly power purchases, ENVY 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.

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Pension and Postretirement Medical Benefit Trust Fund Contributions  In June 2007, we contributed $4.1 million to our pension trust fund and $2.5 million to our postretirement medical trust funds. We do not plan on making any additional contributions to these trust funds in 2007.

Dividend Reinvestment Plan  Our Dividend Reinvestment Plan was reinstated in April 2007. At that time, we elected to change the source of common shares to meet reinvestment needs under the Plan from open market purchases to Original Issue shares. In July 2007, we began using Treasury shares to meet reinvestment needs under the Plan. These elections are expected to result in additional cash flow of $1.0 million to $2.0 million annually.

Our financial statements are prepared in accordance with generally accepted accounting principles in the United States ("GAAP"), requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements. Our critical accounting policies and estimates are described in Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2006 Annual Report on Form 10-K. The following is an update.

Regulatory Accounting  We prepare our financial statements in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71") for our regulated business. The application of SFAS No. 71 results in differences in the timing and recognition of certain revenues and expenses from those of other businesses and industries. We continuously review regulatory assets and other deferred charges to assess ultimate recoverability through retail rates. Based on a current evaluation of the factors and conditions expected to affect future cost recovery, we believe future recovery of regulatory assets is probable. In the event that we determine our regulated operations no longer meet the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, we would be required to write off, as an extraordinary charge to operations, net regulatory assets of $19.8 million on a pre-tax basis as of September 30, 2007. We would also be required to record pension and postretirement medical benefit costs of $29.7 million on a pre-tax basis to Accumulated Other Comprehensive Loss as a reduction in stockholder's equity, and would be required to determine any potential impairment to the carrying costs of deregulated plant. Risks associated with recovery of regulatory assets relate to potentially adverse legislation, and judicial or regulatory actions in the future.

Derivative Financial Instruments We have several power contracts that are derivatives. We enter into forward sale contracts to reduce price volatility, since our long-term power forecasts show energy purchases and production in excess of load requirements. We enter into forward purchase contracts for replacement power energy during Vermont Yankee scheduled refueling outages. The estimated fair values of power contract derivatives are based on over-the-counter quotations or broker quotes at the end of the reporting period, except for one long-term purchase contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3), which is valued using a binomial tree model and quoted market data when available, along with appropriate valuation methodologies.

At December 31, 2006, the estimated fair value of power contract derivatives was an unrealized loss of $8.0 million. During the first nine months of 2007 we entered into several additional forward power contracts that are derivatives. At September 30, 2007, the estimated fair value of all power contract derivatives was a net unrealized loss of $6.2 million ($7.5 million unrealized loss and $1.3 million unrealized gain). Based on a PSB-approved Accounting Order, we record the change in fair value of power contract derivatives as deferred charges or deferred credits on the balance sheet, depending on whether the fair value is an unrealized loss or gain. The corresponding offsets are recorded as current and long-term assets or liabilities depending on the duration.

Income Taxes In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 ("FIN 48"). FIN 48 clarifies the methodology to be used in estimating and reporting amounts associated with uncertain tax positions, including interest and penalties. We adopted FIN 48 on January 1, 2007 as required, and it did not have a material impact on our results of operations or statement of financial position. However, the application of income tax law is complex and we are required to make many subjective assumptions and judgments regarding our income tax exposures. Changes in our subjective assumptions and judgments can materially affect amounts recognized on the income statement and balance sheet.

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In the second quarter of 2007, management determined that it would file amended returns for the 2003 through 2006 tax years requesting refunds totaling $3.0 million. We have categorized the tax position taken in the amended returns as more-likely-than-not to be sustained upon examination based on its technical merits, and recorded a $1.4 million FIN 48 liability in the second quarter of 2007. The FIN 48 liability was reduced by $0.2 million during the third quarter of 2007 due to a true-up of the benefits previously recorded with the filed returns. Because of the impact of deferred tax accounting, if this item were to be disallowed, there would be no impact on the effective tax rate.

The following is a detailed discussion of the results of operations for the third quarter and first nine months of 2007. This should be read in conjunction with the condensed consolidated financial statements and accompanying notes included herein.

Net income for the third quarter of 2007 decreased $2.7 million, or 25 cents per diluted share of common stock, compared to the third quarter of 2006. Net income for the first nine months of 2007 decreased $1.6 million, or 8 cents per diluted share of common stock, compared to the first nine months of 2006. The table below provides a reconciliation of the primary year-over-year variances in diluted earnings per share.

Operating Revenues  Operating revenues and related mWh sales are summarized below.

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Operating revenue decreased $0.7 million in the third quarter and increased $2.1 million in the first nine months of 2007 compared to the same periods in 2006 due to the following:

• Retail sales increased $2.6 million in the third quarter and $13.0 million in the first nine months of 2007 resulting from a 4.07 percent retail rate increase as of January 1, 2007 and higher sales volume. The rate increase added $2.7 million to retail sales revenues in the third quarter and $8.3 million in the first nine months of 2007. Retail sales volume decreased during the third quarter of 2007 compared to the same period in 2006 largely due to cooler weather, but the decrease was offset by higher unit prices partially attributed to a rate redesign effective July 1, 2007, which is revenue neutral on a 12 month basis. Retail sales volume increased during the first nine months of 2007 largely due to an increase in the number of customers resulting from small service territory acquisitions in the second half of 2006 and customer growth in our service territory.
• Resale sales decreased $3.3 million in the third quarter and $10.9 million in the first nine months of 2007 resulting from less excess power available for resale and lower average market prices compared to the same period in 2006. The third quarter 2007 decrease in excess power available for resale resulted from decreased Vermont Yankee purchases due to a derate and unplanned outage during the third quarter of 2007, and lower output from Independent Power Producers. During the first nine months of 2007 this also included second-quarter 2007 scheduled refueling outages at Vermont Yankee and Millstone Unit #3 and increased retail sales volume. The third quarter of 2006 included $4.1 million and the first nine months included $8.4 million for the resale of Vermont Yankee uprate energy as described in Purchased Power below.
• The provision for rate refund decreased revenue by $0.2 million in the third quarter and $0.6 million in the first nine months of 2007. This is related to amounts included in the 4.07 percent rate increase to be refunded to customers because the PSB disallowed our request to recover $1.5 million over two years for Vermont Yankee 2005 incremental refueling costs.
• Other operating revenues increased $0.2 million in the third quarter and $0.6 million in the first nine months of 2007 largely due to revenue from the sale of additional transmission capacity on our share of Phase I/II transmission facility rights, offset by revenue of $0.5 million for mutual aid work that we performed for other utilities in the third quarter of 2006. We expect the sale of Phase I/II transmission facility rights, which extends from April to December, to add about $1.3 million to transmission revenue in 2007.

Operating Expenses   Operating expenses increased $1.9 million in the third quarter and $4.6 million in the first nine months of 2007 compared to 2006. The variances in income statement line items that comprise operating expenses on the Condensed Consolidated Statements of Income are described below.

Purchased Power:   Purchased power expense and related mWh purchases are summarized below.

Purchased power costs decreased $3.1 million in the third quarter and $6.5 million in the first nine months of 2007 compared to the same periods in 2006 due to the following:

• Purchased power costs under long-term contracts decreased $7.0 million in the third quarter and $15.1 million in the first nine months of 2007 primarily resulting from a decrease in purchases from VYNPC due to a third quarter 2007 derate and unplanned outage and a second-quarter 2007 scheduled refueling outage versus full production during the same periods in 2006. Also in 2006, we were required to purchase additional Vermont Yankee uprate power at market prices, totaling about $4.1 million in the third quarter and $8.4 million in the first nine months of 2006. That power was resold in the wholesale energy markets as described in Revenue above. Purchases from Independent Power Producers, most of which are hydro facilities, decreased resulting from less rainfall, partly offset by an increase in average rates. Purchases

• Other purchases increased $5.2 million in the third quarter and $12.5 million in the first nine months of 2007 resulting from replacement energy purchased during the Vermont Yankee outages and derate describe above, and less power available from our joint and wholly owned units including a second-quarter 2007 scheduled refueling outage at Millstone Unit #3 and lower output from our hydro facilities.
• Power costs associated with our ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic decreased $0.9 million in the third quarter and $2.5 million in the first nine months of 2007 resulting from lower collection schedules for Connecticut Yankee and Yankee Atomic decommissioning activities which are nearly complete.
• Other costs decreased $0.4 million in the third quarter and $1.4 million in the first nine months of 2007 primarily resulting from accounting deferrals and amortizations related to Millstone Unit #3 scheduled refueling outages. Based on approved regulatory accounting treatment, we defer the incremental energy costs related to scheduled refueling outages and amortize those costs until the next scheduled refueling outage.

Production:  Production operation costs increased $0.4 million in the third quarter and $1.1 million in the first nine months of 2007 resulting from premium expense for Vermont Yankee outage insurance ($1.5 million amortized over 12 months beginning January 1, 2007).

Transmission - affiliates: These expenses represent our share of the net cost of service of Transco as well as some direct charges for facilities that we rent. Transco allocates its monthly cost of service through the Vermont Transmission Agreement ("VTA"), net of NEPOOL Open Access Transmission Tariff ("NOATT") reimbursements and certain direct charges. The NOATT is the mechanism through which the costs of New England's high-voltage (so-called PTF) transmission facilities are collected from load-serving entities using the system and redistributed to the owners of the facilities, including Transco. These expenses increased $2.1 million in the third quarter and $2.2 million in the first nine months of 2007 primarily from higher rates, and lower reimbursements under NOATT. In the third quarter of 2006, Transco's NOATT reimbursements were higher than its cost of service, partly due to the inclusion of the Northwest Reliability Project in reimbursements. Our share amounted to a $2.0 million reimbursement, which was recorded as a reduction in transmission expense for the third quarter of 2006.

Transmission - other: The majority of these expenses are for purchases of regional transmission service under the NOATT and charges for the Phase I and II transmission facilities. These expenses increased $0.3 million in the third quarter and $1.3 million in the first nine months of 2007 primarily from higher rates and overall transmission expansion in New England, partially offset by lower depreciation expense because the Phase I facility was fully depreciated in 2006.

Other operation: These expenses are related to operating activities such as customer accounting, customer service, administrative and general activities, regulatory deferrals and amortizations, and other operating costs incurred to support our core business. Other operation expenses increased $2.7 million in the third quarter and $4.1 million in the first nine months of 2007 resulting from: 1) a third-quarter 2006 reduction in environmental reserves based on revised cost estimates; 2) higher bad debt expense related to a customer bankruptcy and, in 2006, recovery of a previous charge-off; 3) higher incentive compensation accruals; and 4) higher other costs, including professional services. These were partially offset by lower pension and postretirement medical costs primarily due to additional contributions to the trust funds in March 2006, and lower external audit fees.

Maintenance: These expenses are associated with maintaining our electric distribution system and include costs from our jointly owned generating and transmission facilities. The increase of $2.3 million in the third quarter and $5.4 million in the first nine months of 2007 was primarily related to storm restoration costs resulting from a major storm in April 2007 and storms in August 2007.

Income tax expense (benefit): Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods.

Other Income and Other Deductions These items are related to the non-operating activities of our utility business and the operating and non-operating activities of our non-regulated businesses through Catamount Energy Resources ("CRC"). CRC's earnings were $0.1 million in the third quarter and $0.4 million in the first nine months of 2007 compared to $0.1 million in the third quarter and $0.7 million in the first nine months of 2006. The variances in income statement line items that comprise other income and other deductions on the Condensed Consolidated Statements of Income are described below.

Equity in earnings: Equity in earnings increased $0.7 million in the third quarter and $3.1 million in the first nine months of 2007, principally from our investment in Transco.

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Other income: Other income decreased $1.7 million in the first nine months of 2007. This resulted primarily from two favorable items in 2006 including interest earned on cash proceeds from CRC's December 2005 sale of Catamount Energy Corporation and a gain on the sale of non-utility property. There were no significant variances for the third quarter of 2007.

Other deductions : Other deductions increased $0.1 million in the third quarter and decreased $0.3 million in the first nine months of 2007. There were no significant variances for the third quarter or first nine months of 2007.

Benefit (provision) for income taxes:   Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods.

Power Supply Risks Our material power supply contracts are with Hydro-Quebec and VYNPC. These contracts comprise the majority of our total annual energy (mWh) purchases. The contract for power purchases from VYNPC ends in 2012, and deliveries under the contract with Hydro-Quebec end in 2016 with the level of deliveries beginning to decrease in 2012. These contracts are described in Note 7 - Commitments and Contingencies.

In January 2006, ENVY submitted a renewal application with the NRC for a 20-year extension of the Vermont Yankee plant operating license. ENVY will also need approval of the PSB to continue to operate beyond 2012. At this time, ENVY has not received approvals for the license extension, but in April 2007 it initiated a 30-day exclusive negotiation period required by the original 2002 Vermont Yankee Memorandum of Understanding with the State of Vermont, for potential power purchases by the VYNPC sponsor companies, including us, in the plant's post-March 2012 life extension period. While the 30-day exclusive negotiation period has ended, we are continuing to participate in negotiations for a power contract beyond 2012 and cannot predict the outcome at this time.

There may also be opportunities to negotiate with Hydro-Quebec for future power purchase contracts, and preliminary discussions have begun.

There is a risk that future sources available to replace these contracts may not be as reliable and may include different environmental considerations. Also, the price of such replacement power could be significantly higher than under the current contracts.

There is also a risk that the Vermont Yankee plant could be shut down earlier than expected if ENVY determines that it is not economical to continue operating the plant. An early shut down would cause us to lose the economic benefit of an energy volume equal to 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. Based on projected market prices as of September 30, 2007, the incremental cost of replacement power, including capacity, is estimated to average $54 million annually. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB will allow timely and full recovery of increased costs related to any such shutdown. However, an early shutdown could materially affect our financial position and future results of operations if the costs are not recovered in retail rates in a timely fashion.

Power Supply Management We have entered into several forward sale contracts since January 1, 2007 due to forecasted energy excess during 2007 and 2008. The contracts vary from one to eight months in duration and deliveries vary from 10 MW to 65 MW depending upon our forecast energy excesses in the on-peak and off-peak periods of each month. Some of the forward sale contracts are contingent on Vermont Yankee plant output, eliminating the risks related to sourcing the sale if Vermont Yankee is not operating. Others are firm, thus potentially exposing us to the risk of market price volatility if we are not able to source the contracts with existing resources. Our main supply risk is with Vermont Yankee, and we have outage insurance through December 2008 to mitigate the market price risk during an unplanned outage through that time. In June 2007 we also entered into a forward contract for the purchase of replacement power during the scheduled Vermont Yankee plant outage in late 2008.

The outage insurance for 2007 applies to unplanned Vermont Yankee plant outages of up to 30 consecutive calendar days per outage event, and provides for payment to us of the difference between the spot market price and $40/mWh. The total maximum coverage is $10.0 million, with a $1.0 million total deductible. In 2006, we paid a premium of about $1.3 million for

this insurance coverage. There were no claims under this insurance contract during the first nine months of 2007. In July 2007, we purchased outage insurance coverage for 2008 with terms that are similar to the outage insurance in place for 2007. The total maximum coverage is $12.0 million, with a $1.2 million total deductible. A small portion of the premium was paid in August with the remainder due in December 2007.

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In the third quarter of 2007, the Vermont Yankee plant experienced a reduction in plant output, or derate, after the collapse of a cooling tower at the plant, and a two-day unplanned outage associated with a valve failure. We purchased replacement energy adequate to meet most of our hourly load obligations during this period. The derate and unplanned outage increased our net power costs by about $1.0 million in the third quarter of 2007 through increased purchased power expense and decreased operating revenues due to reduced resale sales. The estimate includes a $0.3 million reduction in purchased power expense due to application of the regulatory liability established for the difference in the premium we paid for Vermont Yankee forced outage insurance and amounts currently collected in retail rates.

Some of the forward power contracts that we enter into are derivatives and therefore the fair value is recorded on the balance sheet. Based on PSB-approved regulatory accounting treatment, changes in the fair value are not included on our income statement. Also see Item 3 - Quantitative and Qualitative Disclosures about Market Risk.

Millstone Unit #3 We have a 1.73 percent joint-ownership interest in Millstone Unit # 3. Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership. During Millstone Unit #3's scheduled refueling outage that began on April 7, 2007, DNC announced that it had discovered indications of cracking in the first stage of the high-pressure turbine. The plant resumed producing power for the grid on May 19, 2007. DNC has evaluated options ranging from replacing or repairing the turbine to continued use as is, and has determined that it will plan to repair the cracks during the next scheduled refueling outage in the fall of 2008. Based on DNC's estimated repair costs, we do not expect our share of the costs to be material.

In January 2004, DNC filed, on behalf of itself and the two minority owners, including us, a lawsuit against the Department of Energy ("DOE") seeking recovery of costs related to 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 is expected to be held in August 2008. We continue to pay our share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to our ownership interest.

In October 2007, DNC filed an application with the NRC for a 7 percent uprate at Millstone Unit #3. If approved, we will be responsible for our share of the costs associated with the uprate and will also receive our share of additional power resulting from the uprate. The incremental cost of the uprate is expected to be below current market rates for the incremental power.

Maine Yankee, Connecticut Yankee and Yankee Atomic We own, through equity investments, 2 percent of Maine Yankee, 2 percent of Connecticut Yankee and 3.5 percent of Yankee Atomic. All of these nuclear plants have been permanently shut down and have completed or are nearing completion of decommissioning. We are responsible for paying our equity ownership percentage of decommissioning costs and all other costs for these plants. At September 30, 2007, the Company had regulatory assets of $2.5 million related to Maine Yankee, $7.4 million related to Connecticut Yankee and $3.0 million related to Yankee Atomic. These estimated costs are being collected from customers through existing retail rate tariffs. These amounts are recorded as nuclear decommissioning liabilities (current and non-current) on the balance sheet with a corresponding regulatory asset. We adjust associated regulatory assets and nuclear decommissioning liabilities when revised estimates are provided.

In August 2007 the NRC amended Yankee Atomic's operating license. This amendment reduced the size of the licensed property to include only the land immediately around the Independent Spent Fuel Storage Installation. Yankee Atomic remains responsible for safe storage of the plant's spent nuclear fuel and waste at the Independent Spent Fuel Storage Installation until the United States Department of Energy meets its obligation to remove the material from the site. Yankee Atomic is also required to maintain $100 million in nuclear liability insurance coverage for the facility.

All three companies are involved in litigation with the DOE regarding storage of spent nuclear fuel. On September 30, 2006, the United States Court of Federal Claims issued a judgment in the spent fuel litigation and awarded damages to all three companies. On December 4, 2006, the DOE filed a notice of appeal to the United States Court of Appeals for the Federal Circuit ("Appeals Court") in all three cases, and on December 14, 2006, all three companies filed notices of cross appeals. In the first quarter of 2007, the Appeals Court issued an order consolidating the three cases, and issued an order making another case a companion appeal to the case, which will result in both appeals being heard consecutively.

Due to the complexity of the issues and the appeals, the three companies cannot predict the amount of damages that will actually be received or the timing of the final determination of such damages. Each of their respective FERC settlements require that damage payments, net of taxes and net of further spent fuel trust funding, be credited to ratepayers including us. We expect that our share of these payments, if any, would be credited to our ratepayers as well. Also see Note 3 - Investments in Affiliates for additional information regarding the DOE litigation.

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New England Wholesale Energy Markets In December 2006, ISO-New England implemented a new market mechanism referred to as the Forward Capacity Market ("FCM") to compensate owners of new and existing generation capacity, including demand reduction. ISO-New England believes that higher capacity payments in constrained areas will encourage the development of new generation where needed. Capacity requirements for load-serving entities, including us, are based on each entity's proportionate share of ISO-New England's prior year coincident peak demand. Based on current projections, we expect the FCM rules will result in an average capacity deficiency of about 35 MW for the rest of 2007, possibly increasing thereafter. Based on specified rates through May 2010, we expect net FCM charges of about $0.3 million for the remainder of 2007 and $1.5 million or more in 2008 and 2009.

We continue to monitor potential changes to the rules in the wholesale energy markets in New England. Such changes could have a material impact on power supply costs.

Transmission As a load-serving entity, we are required to share the costs related to the region's high voltage transmission system through payments made under NOATT. Our allocation of NOATT costs, based on our percentage of network load, is a small fraction of New England's obligation. While this regional cost-sharing approach reduces our costs related to qualifying Vermont transmission upgrades, we pay a share of the costs for new and existing NOATT-qualifying facilities located elsewhere in New England.

There are a number of major transmission projects in Vermont being undertaken by Transco, some of which are already in service. Many of these projects, including most of the so-called Northwest Reliability Project, have been approved by NEPOOL for NOATT cost sharing treatment. However, certain future Vermont transmission facilities may not qualify for such cost sharing, and those costs will be charged locally (within Vermont) rather than regionally. Our share of such costs will be determined by the classification of each project; some will be charged directly to specific utilities and some will be shared by all Vermont utilities.

Transmission services provided by Transco are billed to us under the 1991 Transmission Agreement also referred to as the Vermont Transmission Agreement ("VTA"). We and all other Vermont electric utilities are parties to the VTA. In June 2007, FERC issued an Order combining three FERC filings related to the VTA, including a request by five municipal utilities for FERC approval to withdraw from the VTA and take transmission service under a different tariff, and requests by Transco for revisions to the VTA. Hearings on these proceedings are scheduled to begin in January 2008. Additionally, the parties to these proceedings, including us, have and continue to participate in settlement negotiations. We are not able to predict the outcome of this matter at this time.

Vermont The State of Vermont continues to examine changes to the provision of electric service absent introduction of retail choice. Several laws have been passed since 2005 that impact electric utilities in Vermont. These include: 1) Act 61 - Renewable Energy, Efficiency, Transmission, and Vermont's Energy Future; 2) Act 208 - Vermont Energy Security and Reliability Act; and 3) Act 123 - Regional Greenhouse Gas Initiative. The major provisions of the new laws that could affect our business are described in our 2006 Annual Report on Form 10-K.

While provisions of recently passed laws are now being implemented, there is continued interest in new policies designed to reduce electricity consumption, promote renewable energy and reduce greenhouse gas emissions. Many governmental and non-governmental organizations are pursuing aggressive policies to reduce the emission of greenhouse gases in response to concerns about climate change. In May, the Vermont Legislature passed an energy bill, but it was vetoed by the governor and the veto was sustained during a special legislative session. We expect continued discussion of these matters during the remaining months of 2007, both informally and formally. Furthermore, we are monitoring regional and federal proposals that may have an impact on our operations.

A broad public engagement process led by the DPS has begun in an effort to better understand Vermonters' views on energy issues. The process includes a series of meetings across the state, during which members of the public can voice their concerns and interests, and vote on future energy choices. There will also be an extensive, two-day event with randomly selected

Vermonters, who will receive a detailed overview of the issues and competing interests prior to voting. A report on this public input is expected to be presented by the DPS to the Vermont Legislature, the governor and state utilities in December 2007.

See Note 1 - Summary of Significant Accounting Policies in the accompanying Condensed Consolidated Financial Statements.

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Fair and adequate rate relief through cost-based rate regulation can limit our exposure to market volatility. Except as discussed below, there were no material changes from the disclosures in our Annual Report on Form 10-K for the year ended December 31, 2006.

At September 30, 2007, we had power contract derivatives with a total net estimated fair value of an unrealized loss of $6.2 million. Based on PSB-approved regulatory accounting treatment, changes in the fair value of derivatives are recorded on the balance sheet and do not impact our income statement. Summary information related to the fair value of these derivatives is shown in the table below (in thousands):

Evaluation of Disclosure Controls and Procedures As of the quarter ended September 30, 2007, our management, with participation from the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2007 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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