(1) 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 and Rochester Gas and Electric Corporation. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Neither registrant makes any representations as to information relating to the other registrant.

Abbreviations or acronyms frequently used in this report:

The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. This Form 10-Q contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. Whenever used in this report, the words "estimate," "expect," "believe," "anticipate," or similar expressions are intended to identify such forward-looking statements.

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties and that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated utility industry; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of volatile energy prices, including the enactment of the Domenici-Barton Energy Policy Act of 2005; the operation of the NYISO; the operation of ISO New England, Inc. as an RTO; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements; the company's ability to expand its products and services, including its energy infrastructure in the Northeast; the company's ability to integrate the operations of Berkshire Energy Resources, CMP Group, Inc., Connecticut Energy Corporation, CTG Resources, Inc. and RGS Energy Group, Inc.; the company's ability to achieve and maintain enterprise-wide integration synergies; market risk; the ability to obtain adequate and timely rate relief and/or the extension of current rate plans; the continuation of fixed price supply programs; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; economic growth in the areas in which the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; the effect of the volatility in the equity and fixed income markets on pension benefit cost; the inability of the companies' internal control framework to provide absolute assurance that all incidents of fraud or error will be detected and prevented; and other considerations that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 2.  Management's Discussion and Analysis of Financial Condition
             and Results of Operations

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 financial position and results of operations. Energy East has long-term rate plans for New York State Electric & Gas Corporation, Rochester Gas & Electric Corporation, Central Maine Power Company, Connecticut Natural Gas Corporation, The Southern Connecticut Gas Company and The Berkshire Gas Company. The plans presently provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including exogenous and stranded costs, and provide stable rates for customers and revenue predictability for those six operating companies. The CNG and SCG plans expire at the end of September 2005, and SCG has filed a one-year rate case while CNG intends to operate with the rates established in its current long-term plan, after that plan expires.

Energy East's management focuses its strategic efforts on those areas of the company that it believes would have the greatest effect on shareholder value. Efficient operations are a key aspect of increasing shareholder value. Management has implemented plans to achieve savings through a company-wide restructuring that was completed in early 2004 and continued consolidation of utility support services, including front office functions.

The continuing uncertainty in the 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 the proceedings are difficult to predict. Those proceedings, which are discussed below, could affect the nature of the electric and natural gas utility industries in New York and New England.

The company engages in various investing and financing activities to meet its strategic objectives. The primary goal of investing activities is to maintain a reliable energy delivery infrastructure. Investing activities are funded primarily with internally generated funds. The company plans to invest over $1 billion in its energy delivery infrastructure during 2005 through 2007, including approximately $600 million dedicated to electric reliability. Financing activities are focused on maintaining adequate liquidity, improving credit quality and minimizing the cost of capital.

The accompanying Management's Discussion and Analysis of Financial Condition and Results of Operation for each registrant should be read in conjunction with the Management's Discussion and Analysis of Financial Condition and Results of Operation, financial statements and notes contained in the report on Form 10-K filed by each registrant for the year ended December 31, 2004. Due to the seasonal nature of the registrants' operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Energy East has maintained a consistent energy delivery services strategy over the past several years, focusing on the transmission and distribution of electricity and natural gas rather than the more volatile generation and energy trading businesses. Achieving operating excellence and efficiencies throughout the company is central to this strategy. While Energy East has sold certain noncore businesses and the last of its substantial regulated generation assets, investment in infrastructure that supports the electric and natural gas delivery systems will continue.

Utility Shared Services Corporation, a subsidiary of Energy East, has improved efficiencies and achieved savings through the integration of the companies' information systems, purchasing, accounting and finance functions.

The company's long-term rate plans continue to be a critical component of its success. While specific provisions may vary among the company's public utility subsidiaries, the overall strategy includes creating stable rate environments that allow the companies to earn a fair return while minimizing price increases and sharing achieved savings with customers.

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 Electric Rate Unbundling: In June 2003, as required by an NYPSC Order issued in March 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. Effective January 1, 2005, customers have an opportunity to annually 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. Customers enrolled in the new commodity options between October 1, 2004, and December 31, 2004. Customers who did not make a choice are served under RG&E's variable price option. Approximately 77% of those customers who made a choice selected RG&E's fixed price option for 2005. About 25% of RG&E's overall load is now served under that option.

Errant Voltage: In January 2005 the NYPSC issued an Order Instituting Safety Standards in response to a pedestrian being electrocuted from contact with an energized service box cover in New York City. The incident occurred outside the company's service territory. All New York utilities were directed to respond to that order by February 19, 2005, with a report that provided a detailed voltage testing program, an inspection program and schedule, safety criteria applied to each program, a quality assurance program, a training program for testing and inspections and a description of current or planned research and development activities related to errant voltage and safety issues. The Order Instituting Safety Standards also denies utility requests for recovery of implementation costs and establishes criteria for utilities seeking authorization to recover costs as an incremental expense. The order also established penalties for failure to achieve annual performance targets for testing and inspections at 75 basis points each.

NYSEG and RG&E have reviewed the NYPSC order and jointly filed in early February 2005, with two other New York State utilities, a petition for rehearing that focuses on several areas including the impracticability of the timetable established in the order. In addition, NYSEG and RG&E filed a separate petition for rehearing dealing with the recovery of incremental costs of complying with the order. In response to the order, in late February 2005 NYSEG and RG&E filed a testing and inspection plan that is consistent with the timetable identified in the above noted joint petition for rehearing. NYSEG and RG&E have begun to implement their plans, including testing of equipment. The NYPSC issued a press release following its session on June 15, 2005, indicating it would provide some relief in the testing schedule. On July 21, 2005, the NYPSC issued an

order detailing the revised requirements, which NYSEG and RG&E are reviewing. NYSEG and RG&E have incurred costs of less than $1 million to date and estimate that they will incur total costs of approximately $10 million to comply with the order during 2005. The company is unable to predict what effect, if any, these developments will have on its results of operations, financial position or cash flows.

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive electric 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 vision for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.

In August 2004 the NYPSC issued a Statement of Policy on Further Steps Toward Competition in Retail Energy Markets recommending that all potentially competitive utility functions be opened to competition. While it is not possible to determine when markets will become workably competitive, all utilities will be required to prepare plans to foster the development of retail energy markets. The plans can vary by individual utility and NYSEG and RG&E do not expect the statement of policy to affect their commodity service options under their current rate plans.

NYSEG and RG&E filed their retail access plans with the NYPSC on April 14, 2005. As part of its filing, NYSEG requested NYPSC approval, by September 30, 2005, to continue offering its current commodity options to customers, with new two-year commodity offerings beginning January 1, 2007, that are the same as its current program except for the addition of a program to facilitate ESCO market participation by NYSEG billing and collecting directly from ESCO customers.

NYSEG and RG&E believe that their current commodity option programs are the most comprehensive in New York State, providing a full menu of electric supply choices, including a fixed price option for customers who do not want to be subjected to volatile wholesale electricity prices. Experience has shown that the vast majority of customers want their utility to remain a supply option and prefer a fixed price option. NYSEG's and RG&E's believe that their programs are also among the most successful of any retail access plans in New York State in terms of active participation and customer migration.

In June and July 2005 parties filed comments both in support of and in opposition to NYSEG's and RG&E's retail access plans. Parties also filed comments on a motion NYSEG and RG&E filed on April 1, 2005, asking the NYPSC to open an investigation to establish market monitoring measures and affiliate rules to prevent potential gaming of the energy markets by companies that both own generation and sell electricity in the New York retail markets.

NYSEG and RG&E have also supplied comments in NYPSC proceedings regarding other investor-owned utility programs that are designed to encourage customers to migrate from utilities to ESCOs. NYSEG and RG&E believe that the "PowerSwitch" program implemented by Orange and Rockland Utilities, Inc., which is being touted as a model for the rest of the state, is flawed. In their filing, NYSEG and RG&E have questioned whether the program is consistent with the NYPSC's Uniform Business Practices. NYSEG and RG&E believe the program results may be suspect and should not be used as a basis to expand the program to other utilities. On June 1, 2005, the NYPSC approved Central Hudson Gas & Electric Corporation's retail access plan and rejected NYSEG's and RG&E's comments requesting the NYPSC to not take action on Central Hudson's plan and to suspend the development of new retail access initiatives that are based on flawed models.

NYSEG and RG&E are not able to predict what effect, if any, these latest developments will have on their results of operations, financial positions or cash flows.

CMP Alternative Rate Plan: ARP 2000 began on January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007. On March 15, 2005, CMP submitted its annual compliance filing under ARP 2000. On June 30, 2005, the MPUC approved a settlement by which CMP's distribution prices decreased approximately $3 million for the year effective July 1, 2005. In addition, CMP's transmission rates increased approximately $15 million for the year effective July 1, 2005, to reflect updates to the formula rates for 2004 costs as well as its share of ISO New England reliability charges. This increase enables CMP to recover the actual increases resulting from its share of ISO New England regional transmission costs and its local transmission costs.

New England RTO: In March 2004 the FERC issued an order that accepted a six-state New England RTO as proposed by ISO New England and the New England transmission owners. The order approved a 50 basis point and a 100 basis point ROE incentive adders, but limited application of the 100 basis point adder to regional facilities, subject to suspension, hearing and application of the FERC's Pricing Policy Statement, when it is issued. The order also accepted, subject to suspension and hearing, the New England transmission owner's proposed base level ROE of 12.8% applicable to rates for local and regional transmission service. These rates became effective, subject to refund February 1, 2005. Evidentiary hearings on the final base level ROE and the incentive for new transmission investment were conducted by the FERC in January and February 2005. An initial decision was issued in May 2005 recommending a base level ROE of 10.72%, plus the 50 basis point adder. The New England transmission owners have filed exceptions to the initial decision. A final decision from the FERC on those issues is not expected until the end of 2005. The New England transmission owners and ISO New England implemented the New England RTO effective February 1, 2005. (See Energy East's report on Form 10-K for fiscal year ended December 31, 2004, Item 7, New England RTO.)

NYISO Billing Adjustment: The NYISO frequently bills transmission owners on a retroactive basis when adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission revenue or expense as appropriate when revised amounts can be estimated. On January 25, 2005, the NYISO notified the NYTOs, including NYSEG and RG&E, of errors related to transmission congestion contract billings for periods including May 2000 through October 2002. NYSEG's retroactive billing was approximately $0.7 million and RG&E's was less than $0.1 million for the periods in question. Both amounts were expensed during the first two quarters of 2005.

In a separate issue in March 2005 the FERC issued an order directing the NYISO to modify certain energy prices for May 8 and 9, 2000, and to back bill NYISO market participants, including NYSEG and RG&E. The NYISO and many market participants filed requests for rehearing with the FERC concerning that order. While the FERC has not ruled on these requests for rehearing, on July 8, 2005, the NYISO issued back billings that addressed a number of the May 8 and 9, 2000, issues. NYSEG's back billing was $2.3 million and RGE's was $1.4 million. Both amounts were expensed during the second quarter of 2005.

Locational Installed Capacity Markets (LICAP): The FERC administrative law judge in this proceeding issued a recommended decision in June 2005 essentially adopting the ISO New England LICAP market proposal. CMP and other parties that oppose the ISO New England LICAP market proposal filed exceptions to the recommended decision in July 2005. The FERC is expected to issue a final decision by the end of 2005. CMP cannot predict how the FERC will rule or what modifications the FERC might make to the filing. (See Energy East's report on Form 10-K for fiscal year ended December 31, 2004, Item 7, Locational Installed Capacity Markets.)

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.

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 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, approved by the DPUC, allows SCG to petition the DPUC 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. In October 2004 the DPUC issued a final decision that denied current recovery of exogenous costs but recognized that the costs would be reviewed in SCG's next rate case. In December 2004 SCG filed an appeal with the Connecticut Superior Court concerning certain aspects of the DPUC's decision. SCG filed its brief on May 11, 2005. On June 27, 2005, the DPUC filed a motion to dismiss SCG's appeal as a result of SCG's rate case filing, which is discussed below. The current schedule calls for SCG to file its response to the DPUC motion on August 19, 2005, with a hearing on the motion to occur on August 24, 2005.

SCG Regulatory Proceeding: SCG's IRP expires September 30, 2005. As a result of the DPUC's decision denying recovery of exogenous costs, SCG filed a one-year rate case on April 29, 2005, requesting approximately $35 million of additional revenues, which represents an increase of approximately 11% compared to revenues based on current rates. The rate filing requests, among other items, greater recovery of deferred costs similar to SCG's request for recovery of exogenous costs.

On June 28, 2005, hearings commenced on SCG's filing. On July 1, 2005, the Office of Consumer Counsel filed testimony recommending a rate increase of $0.2 million for SCG. The DPUC is scheduled to rule on SCG's rate request in September 2005. The company is unable to predict the outcome of the proceeding.

FIN 47: In March 2005 the FASB issued FIN 47. FIN 47 clarifies that the term "conditional asset retirement obligation" as used in Statement 143 refers to an entity's "legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity." FIN 47 requires that if an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional asset retirement obligation, it must recognize that liability at the time the liability is incurred. The company does not expect that its application of FIN 47 effective December 31, 2005, will have a material effect on its financial position, results of operations or cash flows. (See Note 6 to the Condensed Financial Statements.)

Operating Activities: Significant operating activities that affected liquidity and cash flows during the first six months of 2005 included the following:

• A $25 million refund to RG&E customers using proceeds from the sale of Ginna, pursuant to RG&E's Electric Rate Agreement. RG&E's Electric Rate Agreement requires additional refunds of $15 million in 2006 and $10 million in 2007.
• Contributions of $54 million to certain of the company's pension plans to bring these plans closer to a fully-funded position. No additional contributions are anticipated during 2005. (See Energy East's report on Form 10-K for fiscal year ended December 31, 2004, Item 8, Financial Statements and Supplementary Data.)
• Natural gas inventories decreased by $55 million as they were drawn down during the heating season.
• Accounts receivable declined by $107 million reflecting collections of higher winter bills.

Investing Activities: Capital spending for the first six months of 2005 was $148 million. Capital spending is projected to be $388 million for 2005 and is expected to be paid for principally with internally generated funds. The company plans to invest over $1 billion in its energy delivery infrastructure during 2005 through 2007, including approximately $600 million dedicated to electric reliability. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates, a customer care system and an Infrastructure Replacement Program.

Financing Activities: The financing activities discussed below include those activities necessary for the company and its principal subsidiaries to maintain adequate liquidity, improve credit quality and ensure access to capital markets. Activities include maintenance of credit facilities, minimal common stock issuances and various medium-term and long-term debt arrangements.

During the six months ended June 30, 2005, the company issued 404,317 shares of common stock, at an average price of $26.52 per share, through its Investor Services Program. The shares issued were original issue shares.

During the second quarter of 2005 the company awarded 241,493 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of approximately $6 million based on the average market price of $26.16 per share of common stock on the dates of the awards.

During the first quarter of 2005 NYSEG auctioned $100 million of Series 2004C pollution control revenue bonds for a period of five years through January 2010, at 3.245%. NYSEG also converted $60 million of Series 1985A pollution control revenue bonds from an annual term put mode to a fixed rate of 4.10% through maturity on March 15, 2015. In May 2005 NYSEG refunded a $65 million 6.15% fixed-rate tax-exempt pollution control note with proceeds from the issuance of $65 million of multi-mode tax-exempt pollution control notes due in 2026.

In March 2005 CMP redeemed at par $25 million of its Series E, 8.125% medium-term notes with proceeds from the issuance of short-term debt. In April 2005 CMP issued $25 million of Series F medium-term notes at 5.78% due in 2035 to repay the short-term debt. In June 2005 CMP redeemed all $22 million of its 3.50% Series Preferred Stock, par value of $100 per share at a redemption price of $101 per share. In June 2005 CMP issued $20 million of Series F medium-term notes at 5.375% due in 2035 to finance the 3.50% Series Preferred Stock redemption. In July 2005 CMP issued $25 million of Series F medium-term notes at 5.43% due in 2035 to fund maturing medium-term notes.

In June 2005 the company and its operating utilities replaced their existing revolving credit agreements with two new revolving credit facilities. Energy East Corporation is the sole borrower in a facility providing maximum borrowings of up to $300 million and the company's operating utilities are joint borrowers in a facility providing maximum borrowings of up to $425 million in aggregate. Sublimits that total to the aggregate limit apply to each joint borrower. The sublimits can be altered within the constraints imposed by maximum limits that apply to each joint borrower. Both facilities have expiration dates in 2010 and require fees in lieu of compensating balances. The prior agreements provided for maximum borrowings of $740 million at December 31, 2004, and $700 million at December 31, 2003. The new facilities contain various covenants and conditions on borrowings, including a limit on each borrower's indebtedness to total capitalization of 0.65 to 1.0 and a restriction on the amount of secured indebtedness that each borrower may maintain. No borrower is in default, or is expected to be in default, under the applicable facility.

Earnings per share from continuing operations for the quarter ended June 30, 2005, decreased 17 cents compared to the quarter ended June 30, 2004, primarily because of:

• The effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements that increased earnings 9 cents per share in 2004. The one-time effects, which contributed 7 cents per share in 2004, include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory treatment. An additional 2 cents per share was recognized in the second quarter of 2004 related to annual credits from the ASGA, for a Ginna incentive and for a revenue increase offset. (See Energy East's report on Form 10-K for the fiscal year ended December 31, 2004, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations). Pursuant to the terms of RG&E's Electric Rate Agreement these credits will occur in different periods in 2005 than in 2004.
• A decrease of 5 cents per share due to higher stock option expense,
• A decrease of 3 cents per share due to higher operating and maintenance expenses, including approximately 2 cents per share for storm-related repairs and maintenance, and
• A decrease of 1 cent per share due to NYISO back billings received by NYSEG and RG&E due to modification of energy prices for May 2000.

Earnings per share from continuing operations, basic for the six months ended June 30, 2005, increased 5 cents compared to the six months ended June 30, 2004, primarily because of:

• An increase of 12 cents per share due to higher margins on electric sales resulting from electric commodity programs in New York,
• An increase of 2 cents per share due to a nonrecurring incentive credit provided for under CMP's ARP 2000 when it achieves savings for customers by restructuring NUG contracts, and
• An increase of 2 cents per share due to higher net revenues on natural gas sales.

These increases were offset by:

• One-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements, as discussed above, that increased earnings 7 cents per share in 2004,
• A decrease of 3 cents per share resulting from an increase in operating and maintenance expenses, including approximately 2 cents per share for storm-related repairs and maintenance, and
• A decrease of 2 cents per share due to NYISO back billings received by NYSEG and RG&E due to modification of energy prices for May 2000.

Operating Revenues: The $47 million increase in operating revenues for the second quarter of 2005 was primarily the result of:

• An increase of $13 million due to higher prices for retail electric energy supplied by NYSEG and RG&E under various commodity options. Higher prices became effective January 1, 2005, for customers who continue to purchase electricity from NYSEG and reflect higher market prices for electricity,

• An increase of $50 million in wholesale revenues. $12 million of this increase resulted from higher prices on the sale of CMP's NUG entitlements that increased on March 1, 2005. The remainder resulted primarily from NYSEG's power supply activities,
• An increase of $8 million resulting from higher retail deliveries, and
• An increase of $3 million in other electric revenues.

Those increases were partially offset by:

• A decrease of $17 million as a result of lower sales of electric energy due to customer migration to ESCOs, and
• A decrease of $7 million as a result of lower prices on retail electric deliveries.

Operating Expenses: The $170 million increase in operating expenses for the second quarter of 2005 was primarily the result of:

• An increase of $105 million as a result of the regulatory treatment in 2004 of RG&E's gain on the sale of Ginna, which included RG&E's recognition of a $319 million pretax gain partially offset by the after tax deferral of the gain of $214 million,
• An increase of $35 million in power purchases largely resulting from increased wholesale sales and higher prices for electric supply purchased for NYSEG's and RG&E's electric commodity customers, including $4 million due to NYISO billing adjustments,
• An increase of $6 million due to higher stock option expense,
• A net increase of $5 million in operating expenses as a result of the sale of Ginna, including an increase in purchased power costs of $30 million, partially offset by decreases of $15 million in other operating and maintenance expenses, $8 million in depreciation and $2 million in other taxes,
• An increase of $9 million due to certain credits to other operating expenses that resulted from RG&E's Electric Rate Agreement and reduced expenses in the second quarter of 2004. These items were primarily the elimination of reserves that had been established pending regulatory treatment, and
• Increases in various other operating and maintenance expenses, excluding Ginna, totaling $11 million. Higher storm costs accounted for approximately $5 million of this increase and higher transmission-related expenses accounted for an additional $4 million. The majority of the increase in transmission expenses resulted from regional cost increases that were allocated to all New England transmission owners.

Operating Revenues: The $84 million increase in operating revenues for the first six months of 2005 was primarily the result of:

• An increase of $42 million due to higher prices for retail electric energy supplied by NYSEG and RG&E under various commodity options,
• An increase of $30 million in other electric revenues including $6 million for CMP's NUG restructuring incentive, and $8 million for RG&E's amortization of the ASGA to offset the incremental cost of power as a result of the Ginna sale,

• An increase of $48 million in wholesale revenues. $15 million of this increase resulted from higher prices on the sale of CMP's NUG entitlements that increased on March 1, 2005. The remainder resulted primarily from NYSEG's power supply activities, and
• An increase of $12 million for increased retail deliveries.

Those increases were partially offset by:

• A decrease of $20 million as a result of lower sales of electric energy due to customer migration to ESCOs, and
• A decrease of $28 million resulting from lower retail prices.

Operating Expenses: The $166 million increase in operating expenses for the first six months of 2005 was primarily the result of:

• An increase of $105 million as a result of the regulatory treatment in 2004 of RG&E's gain on the sale of Ginna, which included RG&E's recognition of a $319 million pretax gain partially offset by the after tax deferral of the gain of $214 million,
• A net increase of $2 million in operating expenses as a result of the sale of Ginna, reflecting an increase in purchased power costs of $63 million, partially offset by decreases of $36 million in other operating and maintenance expenses, $21 million in depreciation and $4 million in other taxes,
• An increase of $40 million in power purchases largely resulting from increased wholesale sales and higher prices for electric supply purchased for the company's electric commodity customers, including $4 million due to NYISO billing adjustments,
• An increase of $4 million in depreciation, excluding Ginna,
• An increase of $9 million due to certain credits to other operating expenses that resulted from RG&E's Electric Rate Agreement and reduced expenses in the second quarter of 2004, and
• Increases in various other operating and maintenance expenses, excluding Ginna, totaling $6 million. Higher storm costs accounted for approximately $6 million of this increase and higher transmission-related expenses accounted for an additional $4 million. Reductions in RG&E's bad debt expense offset these increases by $8 million.

Operating Revenues: The $42 million increase in operating revenues for the second quarter of 2005 was primarily the result of:

• An increase of $27 million as a result of higher market prices of natural gas that were passed on to customers,
• An increase of $10 million in wholesale revenues, and
• An increase of $5 million resulting from higher natural gas retail deliveries.

Operating Expenses: The $39 million increase in operating expenses for the second quarter of 2005 was primarily the result of:

• An increase of $30 million due to purchased natural gas costs, $29 million of which was related to higher prices that were passed on to customers, and
• An increase of $9 million in other operating and maintenance costs, including $3 million related to higher stock option expense and $2 million related to increased maintenance.

Operating Revenues: The $82 million increase in operating revenues for the first six months of 2005 was primarily the result of:

• An increase of $76 million as a result of higher market prices of natural gas that were passed on to customers,
• An increase of $5 million in other natural gas revenues, and
• An increase of $7 million in wholesale sales.

Those increases were partially offset by:

• Decreases in natural gas retail deliveries of $7 million.

Operating Expenses: The $70 million increase in operating expenses for the first six months of 2005 was primarily the result of:

• An increase of $75 million due to higher market prices of purchased natural gas, and
• An increase of $2 million in other operating and maintenance costs.

Those increases were partially offset by:

• A reduction of $7 million because of lower volumes of natural gas purchases.