(1) All shares are owned by CMP Group, Inc., a wholly-owned subsidiary of Energy East Corporation.
⁽²⁾ All shares are owned by RGS Energy Group, Inc. a wholly-owned subsidiary of Energy East Corporation.

This combined Form 10-Q is separately filed by Energy East Corporation, Central Maine Power Company, New York State Electric & Gas Corporation and Rochester Gas and Electric Corporation. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

Item 2.  Management's discussion and analysis of financial condition
             and results of operations

Energy East Corporation's (Energy East or the company) management focuses its strategic efforts on those areas of the company that have the greatest effect on shareholder value. Efficient operations are a key aspect of increasing shareholder value. As discussed below, management has implemented plans to achieve savings through a company-wide restructuring, consolidation of utility support services and other changes.

In addition, because Energy East's primary operations - its electric and natural gas utility operations - are subject to rate regulation, the approved regulatory treatment on various matters could significantly affect the company's operations and, therefore, its financial position and results of operations. In May 2004 Rochester Gas and Electric Corporation (RG&E), an operating company of Energy East, received approval for long-term electric and natural gas rate plans. As a result, Energy East now has long-term rate plans for all of its major utility operating companies including New York State Electric & Gas Corporation (NYSEG), Central Maine Power Company (CMP), Connecticut Natural Gas Corporation (CNG), The Southern Connecticut Gas Company (SCG) and The Berkshire Gas Company (Berkshire Gas). The plans provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including exogenous and uncontrollable costs, and provide stable rates for customers a nd revenue predictability for those six operating companies.

Over the last several years Energy East has focused its strategic efforts on its electric and natural gas delivery operations, rather than on the more volatile electricity generation business, and has sought to rationalize its nonutility businesses to ensure they fit its strategic focus. As discussed below, RG&E successfully completed the sale of its Ginna nuclear generating station (Ginna) to Constellation Generation Group LLC (CGG) on June 10, 2004. In addition, on July 26, 2004, CMP Group, Inc. sold the majority of the assets of its subsidiary, Union Water Power Company (UWP).

The continuing evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings that could significantly affect operations, although the outcomes of those proceedings are difficult to predict. Those proceedings could have an effect on the nature of the electric and natural gas utility industry in New York and New England. Recent events in the proceedings are described below.

The company engages in various investing and financing activities to meet its strategic objectives. Investing activities are conducted primarily to maintain a reliable energy delivery infrastructure and are funded primarily with internally generated funds. Financing activities, therefore, are focused on maintaining adequate liquidity, improving credit quality and minimizing the cost of capital. As a result of the Ginna sale, the company will have funds available to reduce its outstanding debt as well as that of RG&E.

In the first quarter of 2004 the company completed its consolidation of various accounting and finance functions. Energy East recognized a $4 million total liability for an enhanced severance program for 83 accounting and finance employees who were employed through March 31, 2004. The company recorded approximately $2 million of that liability as of the end of the fourth quarter of 2003 and recorded the remaining $2 million of the liability in the first quarter of 2004. The liability was entirely paid off as of June 30, 2004.

The company's electric delivery business consists primarily of its regulated electricity transmission, distribution and generation operations in upstate New York and Maine.

RG&E 2003 Electric and Natural Gas Rate Agreements: In May 2003 RG&E filed a rate case with the New York State Public Service Commission (NYPSC) to recover costs that RG&E has incurred and will continue to incur in providing safe and reliable electric and natural gas service. On May 20, 2004, the NYPSC approved Electric and Natural Gas Joint Proposals (Electric and Natural Gas Rate Agreements) that had been negotiated with Staff of the NYPSC and other interested parties and that address RG&E's electric and natural gas rates through 2008.

Key features of the Electric Rate Agreement include:

• To cover $6 million of replacement purchased power costs incurred in connection with the 2003 Ginna refueling outage;
• To provide the company with revenue equivalent to a $2 million annual increase in electric delivery rates;
• To compensate RG&E for maximizing the sale value of Ginna through a credit to RG&E of $3.3 million annually over the term of the settlement;

• RG&E estimates that at the end of 2008 approximately $121 million will remain in the ASGA, which may be used at the discretion of the NYPSC for rate moderation, among other things.

• Establishing an earnings sharing mechanism to allow customers and stockholders to share equally in earnings above a 12.25% return on equity (ROE) target.
• Creating and expanding initiatives to enable energy service companies (ESCOs) in RG&E's service territory to attract new customers. RG&E will be allowed to increase its earnings sharing threshold to 12.50% by meeting to-be-determined standards designed to measure improvements in its retail access program, such as increasing customer awareness of competitive alternatives and increasing customer migration.

• Ensuring that RG&E continues to maintain the high quality of service and reliability that it currently provides by specifying service quality and reliability standards and capital investment objectives.
  

Key features of the Natural Gas Rate Agreement include:

• Freezing natural gas delivery rates through December 2008, except for the implementation of a merchant function charge that will recover approximately $7 million annually beginning May 1, 2004.
• Implementing a weather normalization adjustment to protect both customers and RG&E from fluctuating revenues due to swings in temperature outside a normal range.
• Implementing gas cost incentive mechanisms to provide a means of sharing with customers future gas supply cost savings achieved by RG&E.
• Establishing provisions similar to those in the Electric Rate Agreement regarding earnings sharing and service quality and reliability. The level for earnings sharing is 12.00%, with the opportunity to increase to 12.25% if certain targets are achieved.

The Electric and Natural Gas Rate Agreements resolve all outstanding issues in the RG&E Cost Deferral Petitions and the RG&E 2002 Electric and Gas Rate Proceeding. In addition, RG&E has withdrawn its appeal of an order the NYPSC issued in March 2003. (See report on Form 10-Q for Energy East and RG&E for the quarter ended March 31, 2004, Item 2, Electric Delivery Business - RG&E Cost Deferral Petitions and RG&E 2002 Electric and Gas Rate Proceeding.)

Upon closing of the Ginna sale, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. This amount fully meets the Nuclear Regulatory Commission's decommissioning funding requirements for Ginna. RG&E retained $77 million in excess decommissioning funds, which is part of the ASGA. The sale agreement includes a 10-year, fixed-price power purchase agreement that calls for CGG to provide electricity to RG&E at 90% of the plant's output.

RG&E Electric Rate Unbundling: In June 2003, as required by NYPSC's Order issued March 7, 2003, RG&E filed documentation with the NYPSC to unbundle commodity charges from delivery charges and to create electric commodity options for all customers. The Electric Rate Agreement provides for that unbundling and for the commodity options. Beginning January 1, 2005, customers will have an opportunity to choose to purchase commodity service from RG&E at a fixed rate or at a price that varies monthly based on the market price of electricity. Alternatively, customers may continue to choose to purchase their commodity service from an ESCO.

RG&E Transmission Project: In September 2003 RG&E applied to the NYPSC for approval to upgrade its electric transmission system. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, NY, area in order to assure adequate service to customers after the planned closing of RG&E's 257 megawatt coal-fired Russell Station in 2007. The estimated cost of the multi-year project is $75 million. Construction on the project is expected to begin in the spring of 2005.

CMP Alternative Rate Plan: In September 2000 the Maine Public Utilities Commission (MPUC) approved CMP's Alternative Rate Plan (ARP 2000). ARP 2000 applies only to CMP's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services. ARP 2000 began January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007. Effective July 1, 2004, CMP's distribution prices decreased by about 1% as a result of inflation being less than the productivity offset for 2004. In addition, CMP decreased its transmission rates to eliminate billings for congestion costs that have been fully recovered and, pursuant to its formula rate approved by the Federal Energy Regulatory Commission (FERC), to reflect CMP's and the New England Power Pool's actual costs for 2003.

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive electricity and natural gas markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets and providing recommendations concerning Provider of Last Resort and related issues. In January 2004 the NYPSC issued a Notice seeking additional comments in light of the passage of time and the evolution of competitive markets. In March and April 2004 NYSEG and RG&E submitted comments supporting periodic assessment of the retail competitive marketplace and opposing the adoption of any policies restricting customer choice of supplier or limiting the availability of supply options from any particular supplier. NYSEG and RG&E believe that the NYPSC should not adopt a single end state vis ion for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.

Regional Transmission Organization: ISO New England and the New England transmission owners, including CMP, made a joint regional transmission organization (RTO) filing with FERC in October 2003. On March 24, 2004, the FERC issued an order (RTO Order) accepting the six-state New England RTO filing submitted by ISO New England and the New England transmission owners, subject to certain conditions. FERC approved a proposed 50 basis point incentive adder to the ROE component, to be recovered in RTO New England's rates for regional network service. The FERC accepted a proposed 100 basis point ROE adder to reward new transmission investment for regional network services (RNS) facilities, subject to suspension, hearing and application of the FERC's Pricing Policy Statement when it is issued. The FERC also accepted, subject to suspension and hearing, the transmission owners' proposed base level ROE of 12.8% on RNS facilities but not on local network system (LNS) facilities. To pro vide parties an opportunity to resolve matters, the FERC instituted settlement procedures covering all matters set for hearing. The initial settlement discussions did not produce a resolution and the parties are conducting discovery of the issues set for hearing. CMP and the other New England transmission owners have requested rehearing on the issue of whether LNS facilities will earn the 12.8% base ROE and incentive adders, and clarification on

other aspects of the FERC's RTO Order. In addition, ISO New England and the New England transmission owners, including CMP, made a joint compliance filing as required by the RTO Order. At this time, CMP and the other New England transmission owners have informed the FERC that it needs to resolve the issues in the request for rehearing and clarification before the New England transmission owners can make a final decision regarding whether and when to join the RTO.

CMP Collective Bargaining Agreement: Effective April 30, 2004, the union contract expired between CMP and the local union of the International Brotherhood of Electrical Workers. On May 5, 2004, the union membership voted to accept CMP's offer for a new contract, which expires on April 30, 2009. The contract provides for wage increases of 3.25% in 2004, 3.0% in each year 2005, 2006 and 2007, and 2.75% in 2008. It also includes provisions for active employees to contribute to medical insurance plans at a level reflecting CMP's cost-sharing philosophy for all such plans by the end of the contract period and for employees who retire on or after July 1, 2005, to contribute toward the cost of medical insurance according to a predetermined schedule.

CMP Stranded Cost Proceeding: Through its stranded cost rates, CMP recovers the above-market costs of its purchased power agreements, as well as costs incurred to decommission and dismantle the nuclear facilities in which CMP has an ownership share, pursuant to Maine statute. The current stranded cost rates were set in 2003 and are scheduled to be updated in February 2005. CMP filed revised stranded cost estimates in July 2004, as ordered by the MPUC. CMP expects an MPUC order setting new stranded cost rates in February 2005.

CMP Nuclear Costs: CMP has ownership interests in three nuclear facilities in New England that have been permanently shutdown, and are in the process of being decommissioned: Maine Yankee Atomic Power Company (38% owned), Connecticut Yankee Atomic Power Company (6% owned) and Yankee Atomic Electric Power Company (9.5% owned) (the Yankee companies). The Yankee companies filed litigation in 1998 charging that the federal government breached contracts it entered into with each of the Yankee companies in 1983 to begin removing spent nuclear fuel from the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear plants, which are owned by the Yankee companies, no later than January 31, 1998, in return for payments by each of the Yankee companies. Two federal courts found that the federal government did breach its contracts with the Yankee companies and other utilities. A trial to determine the monetary damages owed to the Yankee companies for the Department of Energy's (DOE) co ntinued failure to remove spent nuclear fuel began in the U.S. Court of Federal Claims in July 2004. The Yankee companies' individual damage claims are specific to each plant and include costs through 2010, the earliest date the DOE expects that it will begin removing fuel. The Yankee companies' damage claims total approximately $550 million and CMP's sponsor-weighted share is approximately $90 million. The claims also note additional costs that will be incurred for each year that fuel remains at the sites beyond 2010. If the Yankee companies prevail in these cases, any damages awarded by the Court of Federal Claims would be credited to their respective decommissioning or spent fuel trust funds and any remaining funds would be returned to electric customers when decommissioning is complete.

Pursuant to a year 2000 settlement (2000 Settlement) in a prior FERC rate case, Connecticut Yankee, on July 1, 2004, filed a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of the costs of decommissioning. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars compared to the April 2000 estimate of $434 million approved by the FERC in the 2000 Settlement. The revised estimate reflects the fact that Connecticut Yankee is now self-performing all work to complete the decommissioning of the plant and the termination of Bechtel Power Corporation (Bechtel), the turnkey decommissioning contractor, in July 2003. In addition, the revised estimate contains increases in the projected costs of spent fuel storage, security, and liability and property insurance. The estimated remaining decommissioning and long-term spent fuel storage costs as of Decemb er 31, 2003, are approximately $504 million in 2003 dollars.

Connecticut Yankee is seeking recovery of incremental decommissioning costs and other damages from Bechtel and, if necessary, its surety. In turn, Bechtel has filed a complaint in Connecticut Superior Court seeking damages of $93 million for wrongful termination of the decommissioning contract. Connecticut Yankee has filed counterclaims for excess completion costs and other damages. Discovery is underway and a trial has been scheduled for May 2006.

The revised schedule for decommissioning collections is based on the 2003 estimate. Under the revised schedule, increased collections of $93 million annually would commence in January 2005 and extend through December 2010. Any increase in rates approved by the FERC will be charged to Connecticut Yankee's owners, including CMP, whose share of a $93 million increase would be approximately $6 million. Under prior regulatory settlements, CMP is allowed to defer any increased decommissioning costs for future recovery.

On June 10, 2004, the Connecticut Department of Public Utility Control (DPUC) and the Connecticut Office of Consumer Counsel filed a petition with the FERC asking the FERC to determine that, if it should find any of Connecticut Yankee's decommissioning costs were not prudently incurred, the owners may not recover those costs in rates that are ultimately charged to retail customers but must be borne by the owners of Connecticut Yankee. Connecticut Yankee and its owners, including CMP, filed protests to contest this petition. CMP cannot predict the outcome of these proceedings.

The company's natural gas delivery business consists of its regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts.

Natural Gas Supply Agreements: Energy East's natural gas companies - NYSEG, RG&E, SCG, CNG, Berkshire Gas and Maine Natural Gas - have a three-year strategic alliance with BP Energy Company, effective April 1, 2004, for the acquisition of natural gas supply and optimization of transportation and storage services.

NYSEG Natural Gas Rate Plan: NYSEG's Natural Gas Rate Plan, which became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, implements a natural gas supply charge to collect the actual costs of natural gas and contains an earnings sharing mechanism. The earnings sharing mechanism requires equal sharing of earnings between NYSEG customers and shareholders of ROEs in excess of 11.5% for the 27-month period ended December 31, 2004, and in excess of 12.5% for each of the calendar years from 2005 through 2008. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $250 million.

On June 30, 2004, NYSEG filed a Joint Proposal executed by NYSEG and other parties, resolving outstanding issues in NYSEG's Natural Gas Rate Plan related to its natural gas delivery rate design, natural gas economic development plan and its natural gas Affordable Energy Program. Pursuant to NYSEG's Natural Gas Rate Plan, delivery rate designs in the Joint Proposal were developed for each of the remaining years on an overall revenue neutral manner, consistent with the billing units and firm delivery revenues contained in NYSEG's Natural Gas Rate Plan. The company expects the NYPSC to address the Joint Proposal at its open session on September 22, 2004.

SCG Request for Recovery of Exogenous Costs: In December 2003 SCG filed an application with the DPUC to recover approximately $21 million of exogenous costs under its approved Incentive Rate Plan (IRP). The exogenous costs to be recovered include qualified pension and other postretirement benefits expenses, taxes, uncollectible expense and the cost of SCG's Customer Hardship Arrearage Forgiveness Program. Those costs were the result of events that were unanticipated and beyond SCG's control. SCG's IRP decision from the DPUC allows SCG to petition for relief from substantial and material costs resulting from such exogenous events. The DPUC established a docket for this proceeding and hearings were held in April 2004. A DPUC draft decision in this proceeding is now scheduled to be released some time in August. SCG cannot predict the outcome of this proceeding.

CNG's Purchased Gas Adjustment Clause: In April 2002 the DPUC initiated a semiannual review of CNG's Purchased Gas Adjustment Clause (PGA). The DPUC issued its draft decision in December 2002, disallowing approximately $1 million of natural gas costs that would be returned to customers through the PGA. As a result, on December 31, 2002, CNG set up a reserve to recognize a potential $1 million liability for this disallowance. In May 2004 the DPUC issued its final decision in a subsequent PGA case that clarified a number of issues and allowed CNG to reverse the $1 million reserve.

Connecticut Merger-Enabled Gas Supply Savings and Gas Cost Reduction Plan Filings: In 2001 CNG and SCG submitted filings to the DPUC regarding merger-enabled gas supply savings (MEGS) and a gas-cost reduction plan, which covered the initial period April 1, 2001, through September 30, 2001. CNG provided calculations for total MEGS of $1.3 million and SCG provided calculations for total MEGS of $2.2 million. In February 2003, based on its understanding of the components of the MEGS, the DPUC issued a draft decision on CNG's and SCG's filed MEGS and gas-cost reduction plan results, modifying the MEGS amounts to

$134,000 for CNG and $9,000 for SCG. CNG and SCG filed comments and additional detail with regard to the draft decision. On March 26, 2004, the DPUC issued a notice that encouraged the parties to settle the MEGS issue, which resulted in the assignment of Prosecutorial Staff of the DPUC to assist in the settlement process. The docket was suspended to allow the settlement process to proceed. CNG and SCG are diligently working toward settlement of the issues but cannot predict the final outcome of these proceedings.

Sale of Other Businesses: The company continues to rationalize its nonutility businesses to ensure that they fit its strategic focus. On July 26, 2004, UWP, a subsidiary of CMP Group, Inc., sold all of the assets related to its utility locating and construction businesses. The after tax loss resulting from the sale is estimated at $5 million and includes a reduction in the goodwill that was assigned to UWP at the time of Energy East's purchase of CMP Group.

FIN 46R: In December 2003 the Financial Accounting Standards Board (FASB) issued its revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin (ARB) No. 51 (FIN 46R). FIN 46R addresses consolidation of variable interest entities. A variable interest entity is an entity that is not controllable through voting interests and/or in which the equity investor does not bear the residual economic risks and rewards. The company was required to apply FIN 46R to all entities subject to the interpretation as of March 31, 2004. (See Note 7 to the Condensed Financial Statements.)

FASB Staff Position No. FAS 106-2: In May 2004 the FASB issued its FASB Staff Position (FSP) No. FAS 106-2, which addresses how and when a plan sponsor should account for the federal subsidy introduced by the Medicare Prescription Drug, Improvement and Modernization Act of 2003 and could require the plan sponsor to change previously reported information. FSP No. FAS 106-2 is effective for the first interim or annual period beginning after June 15, 2004. When FSP No. FAS 106-2 becomes effective it supersedes FSP No. FAS 106-1. The company, CMP, NYSEG and RG&E will apply FSP No. 106-2 beginning July 1, 2004. (See Note 9 to the Condensed Financial Statements.)

Investing Activities: Capital spending for the first six months of 2004 was $124 million, including nuclear fuel. Capital spending is projected to be $345 million for 2004, including nuclear fuel, and is expected to be paid for primarily with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

During the six months ended June 30, 2004, the company issued 444,122 shares of common stock, at an average price of $23.15 per share, through its Investor Services Program (formerly known as the Dividend Reinvestment and Stock Purchase Plan). The shares issued were original issue shares.

In July 2004 the company replaced its $150 million 364-day revolving credit facility with a $150 million five-year revolving credit facility that expires in July 2009.

During the first quarter of 2004 the company awarded 242,038 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of $6 million based on the market price per share of common stock on the dates of the awards, which averaged $23.90.

NYSEG Financing Activities: In May 2004 NYSEG entered into forward starting swaps on three adjustable-rate pollution control notes to fix the interest rates on the anniversary dates of the notes. NYSEG will receive the Bond Market Association Municipal Swap rate, an indexed floating rate, and pay fixed rates on the notional amounts as follows: 4.387% on $60 million (anniversary date March 15, 2005), 4.330% on $30 million (anniversary date October 15, 2004) and 4.390% on $42 million (anniversary date December 1, 2004).

In July 2004 NYSEG and RG&E replaced their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-year $230 million revolving credit facility with certain banks. NYSEG is permitted to borrow up to $180 million under the facility, RG&E is permitted to borrow up to $75 million, and NYSEG and RG&E are allowed to issue letters of credit totaling up to $40 million, not to exceed a combined total of $230 million.

In August 2004 NYSEG expects to refund $204 million of tax-exempt fixed-rate pollution control notes that have interest rates ranging from 5.70% to 6.05% with proceeds from the issuance of $204 million of multi-mode tax-exempt pollution control notes, which will initially be in a Dutch Auction mode. In July 2004 NYSEG entered into a forward starting swap to fix the interest rate on one of the tax-exempt pollution control notes in the Dutch Auction mode. NYSEG will pay a fixed rate of 3.80% and will receive 67% of the one-month LIBOR rate on a notional amount of $70 million.

RG&E Financing Activities: On March 1, 2004, RG&E redeemed, at par, as required by a mandatory sinking fund provision, $1.25 million of 6.60% Series V preferred stock, Par Value $100, using available cash. On May 5, 2004, RG&E redeemed, at par, the remaining $23.75 million of the 6.60% Series V preferred stock, using available cash. The 6.60% Series V preferred stock, because it was mandatorily redeemable, was classified as a liability as of July 1, 2003, in accordance with FASB Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.

On May 5, 2004, RG&E redeemed its remaining preferred stock, including: $12 million of 4% Series F (120,000 shares), $8 million of 4.10% Series H (80,000 shares), $6 million of 4 3/4% Series I (60,000 shares), $5 million of 4.10% Series J (50,000 share), $6 million of 4.95% Series K (60,000 shares) and $10 million of 4.55% Series M (100,000 shares), all redeemed at a premium. On May 6, 2004, RG&E redeemed, at a premium, $40 million of 7.45% Series first mortgage bonds due July 2023, and the following Series of first mortgage bonds due March 2023: $33 million of 7.64%, $5 million of 7.66%, and $12 million of 7.67%. Those redemptions were financed through available cash and a short-term credit facility. The short-term credit facility was repaid with proceeds from the sale of Ginna.

In July 2004 RG&E and NYSEG replaced their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-year $230 million revolving credit facility with certain banks. RG&E is permitted to borrow up to $75 million under the facility, NYSEG is permitted to borrow up to $180 million, and RG&E and NYSEG are allowed to issue letters of credit totaling up to $40 million, not to exceed a combined total of $230 million.

In August 2004 RG&E expects to refund $60 million of fixed-rate tax-exempt mortgage bonds that have rates ranging from 6.35% to 6.5% with proceeds from the issuance of $60 million of multi-mode tax-exempt pollution control notes, which will initially be in a Dutch Auction mode.

In the second quarter of 2004, RG&E declared common dividends of $170 million in order to rebalance its capital structure after the Ginna sale. These funds will be used to reduce debt outstanding at Energy East.

Other Financing Activities:

In the second quarter of 2004 Berkshire Gas, CNG and SCG renewed their joint $105 million 364-day revolving credit facility. The amounts the companies are permitted to borrow up to: Berkshire Gas - $15 million, CNG - $50 million and SCG - $55 million, not to exceed a combined total of $105 million.

Earnings from continuing operations were $1.12 per share for the six months ended June 30, 2004, compared to $1.10 per share for the six months ended June 30, 2003. The increase is primarily the result of the second quarter effects of the sale of Ginna and RG&E's Electric and Natural Gas Rate Agreements discussed above, and because of integration savings and other cost reductions. Earnings were reduced 5 cents per share due to the accumulated effects of stock-based compensation expenses as a result of the changes in the market value of Energy East stock during the first two quarters of 2004 as compared to the same periods last year. Earnings were reduced another 9 cents per share because of lower natural gas deliveries due to milder weather.

Operating revenues for the second quarter of 2004 decreased $1 million primarily as a result of lower revenues of $10 million due to a change in market structure for RG&E that allows ESCOs to provide electricity and $5 million because of lower prices for CMP's retail customers. Those decreases were partially offset by higher retail deliveries of $10 million and higher wholesale revenues of $9 million for NYSEG.

Operating expenses decreased $111 million primarily due to RG&E's recognition of a $319 million pretax gain on the Ginna sale, partially offset by RG&E's deferral of the gain net of tax of $214 million.

Operating revenues for the six months decreased $27 million. The primary factors were revenue decreases of approximately $21 million because of rate reductions for CMP to reflect lower amortization of storm and demand-side management costs; and $22 million due to a change in market structure for RG&E that allows ESCOs to provide electricity, resulting in lower retail revenues offset by higher wholesale revenues and lower fuel costs. Those decreases were partially offset by increased retail deliveries of $4 million, increased wholesale revenues of $8 million and an $8 million increase in transmission revenues for NYSEG.

Operating expenses for the six months decreased $126 million primarily due to RG&E's recognition of a $319 million pretax gain on the Ginna sale, partially offset by RG&E's deferral of the gain net of tax of $214 million. In addition, operating expenses for the first quarter of 2004 decreased $15 million primarily due to a reduction in purchased power costs.

Operating revenues decreased $24 million for the second quarter of 2004 primarily due to lower deliveries that reduced revenues $40 million, partially offset by higher gas costs that are passed on to customers that increased revenues $16 million.

Operating expenses decreased $12 million compared to the prior year quarter. The primary cause was a decrease in volume of natural gas purchases of $14 million. This decrease was offset by higher natural gas prices of $10 million. Lower wholesale volumes decreased expenses $4 million for the quarter.

Operating revenues increased $18 million for the six months compared to the prior year period. The increase is primarily due to an $80 million increase in revenues due to higher natural gas costs, which are passed on to customers, partially offset by lower deliveries of $40 million. Other items, including lower transportation revenues and wholesale entitlements further decreased revenues.

Operating expenses increased $42 million for the six months ended June 30, 2004, primarily due to higher natural gas prices of $62 million, partially offset by fewer purchases of natural gas of $28 million as a result of lower deliveries.