UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes    X      No        

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date.

As of July 31, 2006, shares of common stock outstanding for each registrant were:

This combined Form 10-Q is separately filed by Energy East Corporation and Rochester Gas and Electric Corporation. Information contained herein relating to either registrant is filed by such registrant on its own behalf. Neither registrant makes any representation as to information relating to the other registrant.

Glossary (continued)

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 that could cause actual results to differ materially from those contemplated in any forward-looking statements are discussed in our Form 10-K for the fiscal year ended December 31, 2005, Item 1A - Risk Factors and Item 7 - MD&A - Market Risk, and also include, among others:

• the deregulation and continued regulatory unbundling of a formerly vertically integrated utility industry,
• our ability to compete in the rapidly changing and increasingly competitive electric and/or natural gas utility markets,
• regulatory uncertainty in a politically-charged environment of escalating and volatile energy prices,
• the effects of the NYPSC End State model experiment adopted in its Collaborative on End State of Energy Competition,
• implementation of the Energy Policy Act of 2005,
• increased state and FERC regulation of, among other things, intercompany cost allocations,
• the operation of the NYISO,
• the operation of ISO-NE as an RTO,
• our continued ability to recover NUG and other costs,
• changes in fuel supply or cost and the success of strategies to satisfy power requirements,
• our ability to expand our products and services including our energy infrastructure in the Northeast,
• the effect of rapidly increasing commodity costs on customer usage and uncollectible expense,
• our ability to achieve and maintain enterprise-wide integration synergies,
• market risk from changes in value of financial or commodity instruments, derivative or nonderivative, caused by fluctuations in interest rates or commodity prices,
• our ability to obtain adequate and timely rate relief and/or the extension of current rate plans,
• the possible discontinuation of fixed-price supply programs in the state of New York,
• nuclear decommissioning or environmental incidents,
• legal or administrative proceedings,
• changes in the cost or availability of capital,
• economic growth in the areas in which we do business,
• extreme weather-related events such as floods, hurricanes, ice storms or snow storms,
• weather variations affecting customer energy usage,
• authoritative accounting guidance,
• acts of terrorism,
• the effect of the volatility in the equity and fixed income markets on the cost of pension and other postretirement benefits,
• the inability of our 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 our publicly disseminated documents and filings.

We 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, our electric and natural gas utility operations, are subject to rate regulation established predominately by state utility commissions. The approved regulatory treatment on various matters significantly affects our financial position, results of operations and cash flows. We have long-term rate plans for NYSEG, RG&E, CMP and Berkshire Gas that currently provide for sharing of achieved savings among customers and shareholders; allow for recovery of certain costs, including stranded costs; and provide stable rates for customers and revenue predictability. NYSEG has filed for an extension of its electric rate plan; its current plan expires December 31, 2006. SCG received approval for new rates that became effective January 1, 2006, and CNG's rates will be reviewed by the DPUC later this year.

We continue to focus our strategic efforts in the areas that have the greatest effect on customer satisfaction and shareholder value. NYSEG implemented a new customer care system in the first quarter of 2006 and RG&E expects to implement a new customer care system in the fourth quarter of 2006.

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 our operations, although their outcomes are difficult to predict. Those proceedings, some of which are discussed below, could affect the nature of the electric and natural gas utility industries in New York State and New England.

The continued evolution of the electric utility industry is evidenced by the enactment of the Energy Policy Act of 2005, which repealed the Public Utility Holding Company Act of 1935 (PUHCA). With the repeal of PUHCA, the FERC and state utility commissions have new authority to regulate and monitor, among other things, intercompany cost allocations of holding companies such as Energy East.

We engage in various investing and financing activities to meet our strategic objectives. Our primary goal for investing activities is to maintain a reliable energy delivery infrastructure. We fund our investing activities primarily with internally generated funds. We plan to invest nearly $2 billion in our energy delivery infrastructure over the next five years, including approximately $900 million dedicated to electric reliability. We focus our financing activities on maintaining adequate liquidity and credit quality and minimizing our cost of capital.

Our MD&A for the quarter and six months ended June 30, 2006, should be read in conjunction with our MD&A, financial statements and notes contained in our report on Form 10-K for the fiscal year ended December 31, 2005. Due to the seasonal nature of our operations, financial results for interim periods are not necessarily indicative of trends for the annual period.

We have maintained a consistent energy delivery and services strategy over the past several years, focusing on the safe, secure and reliable transmission and distribution of electricity and natural gas. We have sold a majority of our noncore businesses and our regulated generation assets and we continue to invest in infrastructure that supports our electric and natural gas delivery systems. Achieving operating excellence and efficiencies throughout the company is central to our strategy.

Our long-term rate plans continue to be a critical component of our success. While specific provisions may vary among our public utility subsidiaries, our overall strategy includes creating stable rate environments that allow those subsidiaries to earn a fair return while minimizing price increases and sharing achieved savings with customers. We offer the most comprehensive commodity programs in New York State, providing a full menu of electricity supply choices, including a fixed price option for customers who do not want to be subject to volatile wholesale electricity prices. (See NYSEG Electric Rate Plan Extension and Other Proceedings in the NYPSC Collaborative on End State of Energy Competition.)

Our electric delivery business consists primarily of our regulated electricity transmission, distribution and generation operations in upstate New York and Maine.

NYSEG Electric Rate Plan Extension: In September 2005 NYSEG filed a six-year Electric Rate Plan Extension with the NYPSC, to commence on January 1, 2007, which is the day after the end of its current rate plan. As part of its filing, NYSEG proposed to decrease customers' bills prior to the commencement of the rate plan extension by implementing a customer bill credit effective for the four-month period from September 1, 2006, through December 31, 2006. In particular, NYSEG proposed to return to its electric customers $24 million from its ASGA, initially created as a result of the sale of NYSEG's generating stations. The ASGA has been enhanced during NYSEG's current rate plan with its customers' share of earnings resulting from the earnings sharing mechanism. NYSEG's Electric Rate Plan Extension, as subsequently amended, also proposed, beginning on January 1, 2007, to reduce the nonbypassable wires charge by $168 million and increase delivery rates by $104 million, thereby maintaining an annualized overall electricity delivery rate decrease of approximately $64 million, or 8.6%. NYSEG proposed to accomplish the reduction in its nonbypassable wires charge, which would more than offset the increase in delivery rates, by accelerating benefits from certain expiring above-market NUG contracts and capping the amount of above-market NUG costs over the term of the rate plan extension (referred to as NYSEG's NUG levelization proposal). NYSEG also proposed to increase its equity ratio from 45% to 50%. In addition, NYSEG's proposal would allow customers to continue to benefit from merger synergies and savings.

In early February 2006 Staff of the NYPSC (Staff) and six other parties submitted their direct cases. Staff presented only a one-year rate case. In its presentation, Staff proposed a delivery rate decrease of approximately $83 million, or about 13.4%, which would equate to an overall delivery rate decrease of approximately $226 million, or about 36.5%, including NYSEG's proposed nonbypassable wires charge reduction for the 2007 rate year. Staff neither rebutted nor addressed NYSEG's revised and updated rate plan extension proposal, including its NUG levelization proposal. Staff also opposed NYSEG's proposal to extend its Voice Your Choice program. Staff has also raised several retroactive accounting issues which, if accepted by the NYPSC, could have a material effect on 2006 earnings.

NYSEG filed its rebuttal case on February 21, 2006, responding to Staff's one-year rate case proposal by proposing to increase delivery rates by approximately $58 million, beginning on January 1, 2007. NYSEG also proposed to amortize an equivalent portion of the ASGA liability through a customer bill credit in the nonbypassable wires charge to offset the delivery increase, resulting in no delivery rate change for 2007.

Hearings in this proceeding concluded on April 21, 2006, and various parties filed briefs on April 26, 2006, and May 10, 2006.

On June 9, 2006, the ALJs assigned to NYSEG's electric rate plan extension proceeding issued their RD. The RD, among other things, recommends:

• A decrease in delivery rates of $37 million. NYSEG's most recent update in the proceeding requested a $58 million increase in delivery rates.

• A 9.3% ROE. NYSEG had requested an 11% ROE.

• A significant modification to NYSEG's commodity options program, including:

NYSEG believes that the commodity options program, as recommended, is unworkable and inconsistent with the development of a competitive retail market for supply. In particular, the lower allowance used to set the supply rate does not cover the cost and risk of providing fixed price electricity at retail and would stifle participation by retail energy service providers. If the commodity portion of the RD were adopted as proposed, NYSEG could not offer fixed price electricity to its customers on those terms.

If the RD were adopted in its entirety by the NYPSC, the RD would have a significant adverse effect on NYSEG's financial condition and results of operations. In addition to the items noted above, the RD ignores over $25 million of forecasted expenses, which, if the RD were adopted, would force NYSEG to cut operating, maintenance and capital spending, resulting in significant workforce reductions and degradation in current levels of customer service. It is also likely that NYSEG would be forced to file a new electric rate case.

NYSEG filed briefs objecting to certain aspects of the RD on June 29, 2006, and opposing objections of other parties on July 14, 2006. Further, NYSEG continues to support the adoption of a six-year rate plan extension, including its NUG levelization proposal to moderate the delivery rate increase, and its proposal to extend its Voice Your Choice program. A final NYPSC decision is expected in August 2006. NYSEG cannot predict the outcome of this proceeding.

Flood Damage in NYSEG's Service Territory: A major flood affected certain regions of NYSEG's service territory beginning on June 27, 2006, resulting in extensive damage. Pursuant to the terms of its current electric and natural gas rate plans, NYSEG will defer for future cost recovery virtually all incremental operating and maintenance costs, net of insurance proceeds, resulting from the flooding. NYSEG is still assessing the full magnitude of those costs, which it expects to be in excess of $5 million.

RG&E Dispute Settlement Related to NMP2 Exit Agreement: In November 2001 RG&E and three other NMP2 joint owners, including Niagara Mohawk Power Corporation (Niagara Mohawk), sold their interests in NMP2 to Constellation Nuclear, LLC. In connection with the sale of NMP2, RG&E informed Niagara Mohawk that RG&E's payment obligations and rights to certain TCCs would cease according to the terms of an exit agreement executed by RG&E and Niagara Mohawk in June 1998. Niagara Mohawk disagreed with RG&E's position, claiming that RG&E must continue to make annual payments that were to decline from about $7 million per year in 2002 to $4 million per year in 2007, and remain at that level until 2043. In August 2001 RG&E filed a complaint asking the New York State Supreme Court, Monroe County, to find that, as a result of the sale of its interest in NMP2, RG&E has no further obligation to make payments under the exit agreement and that the TCCs to which RG&E was entitled under the exit agreement should be returned to and accepted by Niagara Mohawk.

In the first quarter of 2006, RG&E and Niagara Mohawk stayed the litigation and entered into confidential mediation with the support of the NYPSC. On June 29, 2006, the parties executed a settlement agreement that provides for RG&E's one-time payment of $34 million to Niagara Mohawk and further provides that RG&E retains the rights and obligations related to the TCCs until 2043, including the value accumulated to date of approximately $4 million. The settlement agreement is contingent upon the fulfillment of certain closing conditions, including FERC acceptance of an amendment to and restatement of the exit agreement. RG&E expects a judgment from the FERC in the third quarter of 2006. In accordance with the 2001 settlement and order associated with the transfer of RG&E's share of NMP2 to Constellation Nuclear and RG&E's Electric Rate Agreement. RG&E will adjust its regulatory asset established as a result of the sale of NMP2 for the amount of the $34 million payment to Niagara Mohawk, which will be offset by the accumulated TCC amount of approximately $4 million and any future TCC amounts. RG&E's results of operations are not affected by the settlement of this dispute.

Niagara Power Project Relicensing: The NYPA's FERC license with respect to the Niagara Power Project expires on August 31, 2007. In order to continue to operate the Niagara Power Project, the NYPA filed a relicensing application in August 2005. The NYPA's relicensing process is important to NYSEG's and RG&E's customers because the companies are allocated an aggregate of over 360 MWs of Niagara Power Project power based on their contracts with the NYPA. (NYSEG and RG&E also receive allocations from the St. Lawrence Project pursuant to those same contracts.) The contracts expire on August 31, 2007, upon termination of the NYPA's FERC license. The annual value of the Niagara allocation to the companies at current electricity market prices is approximately $100 million and the loss of the allocation would increase NYSEG's and RG&E's residential customer rates. However, the NYPA has stated that the allocation of Niagara Power Project power to NYSEG and RG&E should not be addressed in the relicensing proceeding and that the disposition of the power will be in accordance with state and federal requirements.

NYSEG and RG&E filed a motion in November 2005 to intervene in the relicensing proceeding and in December 2005 submitted comments arguing that the FERC should (1) consider power allocation issues (including to NYSEG and RG&E) in its review of the application (2) require the NYPA to update the record with information concerning the benefits of the allocation to NYSEG and RG&E customers and (3) require the NYPA to meet with NYSEG and RG&E to discuss their allocations and the effects on their customers of the withdrawal of the allocations. In January 2006 the NYPA answered those comments, arguing that the FERC should ignore certain issues that NYSEG and RG&E raised and that allocation issues are not an appropriate question in the relicensing proceeding. NYSEG and RG&E filed a response to NYPA's answer in January 2006, and continue to be active participants in the proceeding. NYSEG and RG&E are unable to predict the outcome of this proceeding.

CMP Alternative Rate Plan: In December 2005 CMP and the Office of the Public Advocate filed with the MPUC a stipulation for an extension of CMP's ARP 2000. The stipulation was also supported by low-income customer advocates, and a coalition of industrial energy customers signed the stipulation agreement. The stipulation maintained the provisions of CMP's ARP 2000 and proposed a three-year extension with four additional items. The stipulation provided for a 0.5% increase in the scheduled productivity offset of 2.75% for July 2006 and provided for productivity offsets averaging 2% for 2008, 2009 and 2010. The stipulation included an additional $2.2 million in assistance for low-income customers annually starting in 2006. Under the stipulation, CMP agreed to educate its customers on the regional benefits of adjusting usage during peak hours and demand periods and also agreed to limit the promotion of increased usage during specified higher demand periods. Finally, CMP agreed to commit to investing an additional $25 million through 2010 for enhancements to the reliability, safety and security of its distribution system.

In February 2006 the MPUC approved that portion of the stipulation increasing assistance to low-income customers for one year. On April 28, 2006, the Staff of the MPUC filed its analysis and recommendations with the MPUC commissioners, opposing the stipulation. CMP and the stipulating parties responded to the Staff's recommendations in a brief filed on May 19, 2006. On June 5, 2006, the MPUC determined that the stipulation as proposed was not in the public interest and on June 21, 2006, the MPUC agreed to dismiss the proceeding at the request of the stipulating parties. CMP will continue to operate under the terms of ARP 2000, which expires in December 2007.

Energy East Corporation

CMP Nuclear Costs: CMP owns shares of stock in three companies that own nuclear generating facilities in New England that have been permanently shut down, and are decommissioned or in process of being decommissioned: Maine Yankee Atomic Power Company (38% ownership), Connecticut Yankee Atomic Power Company (6% ownership) and Yankee Atomic Electric Power Company (9.5% ownership). (See report on Form 10-K for Energy East for the fiscal year ended December 31, 2005, Item 7 - MD&A, Electric Delivery Business Developments.)

Pursuant to a FERC approved settlement, in July 2004 Connecticut Yankee filed for FERC approval of a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of decommissioning costs. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars and result in annual collections of $93 million from Connecticut Yankee's owners, including CMP. The revised estimate reflects increases in the projected costs for spent fuel storage, security, liability and property insurance and the fact that Connecticut Yankee had to take over all work to complete the decommissioning of the plant due to its termination of its contract with Bechtel, the turnkey decommissioning contractor, in July 2003. Bechtel filed a lawsuit in Connecticut state court challenging that termination and Connecticut Yankee filed a counterclaim to recover damages caused by Bechtel's breach of contract and termination. In April 2006 Connecticut Yankee and Bechtel settled this matter. Any amount Connecticut Yankee recovers from Bechtel will be credited to its decommissioning costs and any remaining decommissioning funds would be returned to electric customers when decommissioning is complete.

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: NYSEG and RG&E have 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. is flawed, since it results in customers being switched to ESCOs without complete information on the program. In their filing, NYSEG and RG&E question whether the "PowerSwitch" program is consistent with the NYPSC's Uniform Business Practices. NYSEG and RG&E believe the program results are suspect and should not be used as a basis to expand the program to other utilities. In June 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.

In a related matter, in July 2005, the NYPSC issued a notice soliciting comments on a Staff proposal on statewide guidelines for ESCO Referral Programs. As a result of experience gained since the Policy Statement was issued in August 2004, the NYPSC Staff has identified a need for statewide simplicity, consistency and uniformity, to the extent practicable, in ESCO Referral Programs. In September and October 2005 NYSEG and RG&E filed comments urging rejection of the proposal and objecting to the proposal to the extent that it will require all utilities to adopt a "PowerSwitch" type program. In a December 2005 order the NYPSC established procedures for utilities to follow in implementing ESCO Referral Programs based on the Orange & Rockland model, as modified and enhanced with additional consumer protection measures. The NYPSC has approved ESCO Referral Programs for Orange & Rockland, Central Hudson, Niagara

Mohawk Power Corporation, Consolidated Edison Company of New York, Inc., and National Fuel Gas Distribution Corporation. Pursuant to an NYPSC order, RG&E has initiated a collaborative with interested parties for the purpose of RG&E implementing an ESCO Referral Program. They are discussing the effects such a program would have on RG&E's Voice Your Choice program. The NYPSC permitted NYSEG to address the ESCO Referral Program within the context of its electric rate plan extension described above. (See NYSEG Electric Rate Plan Extension.)

Locational Installed Capacity Markets: In 2003 the FERC required ISO-NE to file a proposed mechanism to implement, by January 1, 2006, location or deliverability requirements in the installed capacity or resource adequacy market to ensure that generators that provide capacity within areas of New England are appropriately compensated for reliability. In response, in 2004 ISO-NE developed and filed with the FERC a market proposal based on an administratively set demand curve (previously referred to as locational installed capacity or LICAP). In June 2005 the FERC ALJ issued an initial decision, essentially adopting the ISO-NE market proposal, with minor modifications.

CMP and other parties that oppose the ISO-NE market proposal filed exceptions to the recommended decision in July 2005. The Energy Policy Act of 2005 included a "sense of Congress" provision to the effect that the FERC should carefully consider the objections of the New England states to the proposal in the recommended decision. In addition, the MPUC, CMP, the DPUC (representing the state of Connecticut) and the OCC, joined with several Massachusetts parties and filed briefs with the FERC asking that the parties conduct settlement discussions to consider alternatives, and that the FERC consider other alternatives to the market proposal. In response to those protests, the FERC has delayed any possible implementation until October 1, 2006, at the earliest, and granted oral arguments to consider opposition to the market proposal and possible alternatives. Following oral arguments, the FERC granted the request to conduct settlement discussions to consider alternatives. Settlement discussions began in November 2005 and in January 2006 the settlement ALJ reported to the FERC that most of the parties had reached an agreement in principle on an alternative. The alternative would provide fixed transitional capacity payments from 2006 until 2010 and provide capacity payments based on a Forward Capacity Market Auction thereafter. CMP opposed this settlement agreement because of the unjustified cost of the transition payments to electric customers in

Maine. The ISO-NE and a majority of NEPOOL participants supported the settlement agreement. That alternative has been filed with the FERC as a component of a comprehensive settlement agreement.

Although, CMP objects to certain elements of the settlement agreement, it elected not to file opposing comments with the FERC. The MPUC, among other parties, filed comments opposing the settlement agreement, because the proposal could have an adverse effect on Maine's economy by increasing its generation supply rates, including standard offer rates, by an estimated 5% to 10%. On June 15, 2006, the FERC issued an order accepting the settlement agreement without modification. The MPUC and other parties opposed to the settlement agreement filed a request with the FERC asking it to reconsider its June 15 order. If the opposing parties' efforts to prevent the alternative resource adequacy market are unsuccessful, any resulting increase in costs associated with regional installed capacity will be reflected in Maine consumers' generation supply rates beginning in December 2006. CMP cannot predict the outcome of these proceedings.

MPUC Inquiries into Maine Initative for Long-Term Utility Capacity Contracts and
New England RTO: Maine lawmakers enacted legislation in 2006 that requires the MPUC to conduct an inquiry concerning whether or not CMP and other Maine electric utilities should continue to participate in the New England RTO, as operated by the ISO-NE. That legislation also requires the MPUC to conduct further inquiry regarding regional energy markets and generation deregulation. Among the actions initiated by such legislation is an MPUC inquiry into the development of a Maine electric resource adequacy plan and the use of long-term generating capacity contracts between utilities and capacity suppliers as a mechanism to support such a plan. The MPUC's inquiry is expected to lead to further proceedings, including the development of implementing rules and a series of reports to the Maine Legislature. The long-term contracting rules and the first report on resource adequacy will be submitted to the legislature for further action in early 2007. In a related inquiry, the MPUC will consider whether it believes that Maine's transmission and distribution utilities should continue to participate in the New England RTO. This inquiry will consider the legal authority, the costs and benefits of and alternatives to an RTO, and will result in a report to the Maine Legislature. CMP will participate in these MPUC proceedings and cannot predict the outcome of these inquiries.

Our natural gas delivery business consists of our regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Massachusetts and Maine.

CNG Regulatory Proceeding: In March 2005 CNG responded to a DPUC request pertaining to CNG's IRP that subsequently expired on September 30, 2005, indicating that CNG's existing rates would continue in effect after the expiration of the IRP, but the earnings sharing mechanism, the rate stay-out commitment, the exogenous cost provision and provisions involving merger-enabled gas cost savings would no longer be applicable.

On March 21, 2006, the DPUC notified CNG that it had initiated a general rate review of CNG pursuant to Connecticut General Statutes, which state that the DPUC must conduct a financial review or require a rate case every four years. On August 1, 2006, CNG notified the DPUC of its intent to submit a general rate filing by the end of September 2006, requesting a net rate increase of $28 million, or 7.9%, in base delivery revenues effective April 1, 2007.

FIN 48: In July 2006 the FASB released FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with the FASB's Statement 109 by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or to be taken in a tax return. The evaluation of a tax position is a two-step process. The first step is for an entity to determine if it is more likely than not that a tax position will be sustained upon examination. The second step involves measuring the amount of tax benefit to be recognized in the financial statements based on the largest amount of benefit that meets the prescribed recognition threshold. The difference between the amounts based on that position and the position taken in a tax return is generally recorded as a liability. FIN 48 is effective for fiscal years beginning after December 15, 2006. Upon adoption of FIN 48, the cumulative effect of applying the provisions of FIN 48 must be reported as an adjustment to the opening balance of retained earnings for that fiscal year. We will adopt FIN 48 effective January 1, 2007. We are currently assessing the effect FIN 48 would have on our (including RG&E's) results of operations, financial position and cash flows, but expect that it will not be material.

and prior service costs as a component of other comprehensive income, and adjust accumulated other comprehensive income as amounts are recognized as components of net periodic benefit cost; adjust retained earnings for any remaining transition asset or obligation, net of tax; revise certain related disclosures; and measure plan assets and benefit obligations as of the date of the year-end balance sheet.

Two public roundtable meetings were held on June 27, 2006, and a final Statement is expected to be issued in September 2006. For public companies, the recognition of a plan's funded status and related disclosure provisions are proposed to be effective for fiscal years ending after December 15, 2006, with earlier application encouraged. The provisions related to measuring plan assets and benefit obligations as of the date of the year-end balance sheet would be applied for public companies for fiscal years beginning after December 15, 2006, and earlier application would be encouraged. Energy East and RG&E each already measure plan assets and benefit obligations as of the year-end balance sheet date. Adoption of a final standard, consistent with proposed modifications to the Exposure Draft, effective for the fiscal year ended December 31, 2006, could have a material effect on Energy East's and RG&E's financial position by reducing prepaid benefits and common stock equity, but would not affect their results of operations or cash flows.

Operating Activities: Significant operating activities that affected cash flows during the six months ended June 30, 2006, included the following:

• A reduction in accounts payable of $225 million that reduced cash primarily due to payments for natural gas purchases and purchased power,
• Decreased receivables that increased cash by $173 million, and
• A reduction in natural gas inventory that increased cash by $79 million.

While the foregoing represent normal activity for the period, the amounts are greater than normal due to higher energy prices.

Investing Activities: Capital spending for the six months ended June 30, 2006, was $153 million. We project capital spending of $442 million for 2006 and expect to pay for it principally with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, and compliance with environmental requirements and governmental mandates, and includes RG&E's transmission project and new customer care system.

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

We repurchased 250,000 shares of our common stock in February 2006, primarily for grants of restricted stock. In February 2006 we awarded 248,320 shares of our common stock, issued out of our treasury stock, to certain employees through our Restricted Stock Plan, at a weighted-average grant date fair value of $24.83 per share of common stock awarded.

In the fourth quarter of 2005, instead of issuing new shares, we began purchasing shares of our common stock in the open market for dividends reinvested through our Investor Services Program. Therefore, our 2006 cash outflows for dividends equal the amount of our dividends as shown on our retained earnings statement.

In January 2006 CMP issued $10 million of Series F medium-term notes at 5.27%, due in 2016, and $30 million of Series F medium-term notes at 5.30%, due in 2016, to refinance maturing debt.

In April 2006 NYSEG issued $12 million of Series 2006A tax-exempt multi-mode bonds, at an initial interest rate of 3.10%, which is presently reset weekly in an auction process, due in 2024, to refinance $12 million of maturing debt that had an interest rate of 6%.

In June 2006 we extended for one year our two revolving credit facilities. Energy East is the sole borrower in a facility providing maximum borrowings of up to $300 million and our operating utilities are joint borrowers in a facility providing maximum borrowings of up to $475 million in aggregate. Sublimits that total to the aggregate limit apply to each joint borrower and can be altered within the constraints imposed by maximum limits that apply to each joint borrower. Both facilities have expiration dates in 2011 and require fees on undrawn borrowing capacity. Energy East pays a facility fee of 10 basis points annually on its $300 million revolver and each joint borrower pays a facility fee on its revolver sublimit, ranging from 6 to 10 basis points annually depending on the rating of its unsecured debt. For purposes of calculating the maximum ratio of consolidated total debt to total capitalization, we have amended both facilities to exclude from consolidated net worth the balance of 'Accumulated other comprehensive income (loss)' as it appears on the consolidated balance sheet. This change anticipates the potential effect of the FASB's Pension Exposure Draft on total capitalization. No borrower is in default, and no condition exists that is likely to create a default, under either facility.

On July 24, 2006 we redeemed all of our 8 1/4% junior subordinated debt securities at par and expensed approximately $11 million of unamortized debt expense in July 2006 in connection with the redemption. The redemption was financed by the issuance of $250 million of unsecured long-term debt at 6.75%, due in 2036, and by the issuance of short-term debt. (See Note 7 to our Condensed Consolidated Financial Statements.) In July 2006 we settled the hedges we had entered into in connection with the refinancing at a gain of approximately $15 million, which we will amortize over the life of the new debt.

In November 2006 Energy East's $232 million 5.75% note matures. Energy East has entered into an arrangement to hedge the interest rate in connection with the refinancing of that security.

Earnings per share for the quarter ended June 30, 2006, increased 7 cents compared to the quarter ended June 30, 2005, primarily because of:

• An increase of 14 cents per share due to higher margins on electricity sales, including 4 cents per share for recovery of undercollected transition charges and 2 cents per share for adjustments to the nonbypassable wires charge. The transition charge reflects the difference between the market price of electricity and the prices set by our long-term electricity supply contracts.

That increase was offset by:

• A decrease of 2 cents per share for lower net margin on natural gas sales, and

• A decrease of 4 cents per share due to higher operating and maintenance expenses, including increases of approximately 9 cents per share for higher uncollectible reserves (reflecting both an increase in 2006 and the effect of a decrease in 2005), partially offset by a decrease of 3 cents per share for lower stock option expense.

Earnings per share, basic for the six months ended June 30, 2006, decreased 7 cents compared to the six months ended June 30, 2005, primarily because of:

• A decrease of 9 cents per share resulting from increased operating and maintenance costs including 10 cents per share for higher uncollectible reserves (reflecting both an increase in 2006 and the effect of a decrease in 2005) and 3 cents per share for storm-related repairs partially offset by a decrease of 2 cents per share for lower stock option expense,
• A decrease of 5 cents per share for higher interest expense resulting from higher rates on short-term and variable rate debt and higher carrying costs on regulatory liabilities,
• A decrease of 2 cents per share for lower net margin on natural gas sales, and

• A decrease of 3 cents per share resulting from increased depreciation expense and other taxes. The depreciation increase was primarily due to the implementation of NYSEG's customer care system.

Those decreases were partially offset by:

• An increase of 12 cents per share due to higher margins on electricity sales, including 8 cents per share for lower earnings sharing accruals and 2 cents per share for adjustments to the nonbypassable wires charge.

Operating Revenues: The $30 million increase in operating revenues for the second quarter of 2006 was primarily the result of:

• An increase of $16 million in wholesale revenue primarily resulting from higher volumes at NYSEG and RG&E,
• An increase of $15 million due to higher prices for retail electric energy supplied by NYSEG and RG&E under various commodity options where they provide supply, and
• An increase of $8 million in other revenues, including $6 million for nonbypassable wires charge accruals.

Those increases were partially offset by:

• A decrease of $8 million resulting from reduced electricity sales under the companies' commodity programs, and
• A decrease of $3 million resulting from lower retail deliveries.

Operating Expenses: The $8 million increase in operating expenses for the second quarter of 2006 was primarily the result of:

• An increase of $10 million for higher uncollectible reserves, partially offset by a decrease of $2 million for various other items.

Operating Revenues: The $47 million increase in operating revenues for the six months ended June 30, 2006, was primarily the result of:

• An increase of $58 million in wholesale revenue primarily resulting from higher volumes at NYSEG and RG&E,
• An increase of $28 million due to higher prices for retail electric energy supplied by NYSEG and RG&E under various commodity options where they provide supply, and
• An increase of $34 million in other revenues including $20 million in lower accruals for earnings sharing and $6 million for the nonbypassable wires charge. The $20 million increase includes $14 million from the first quarter of 2006 for the finalization of the actual amount of earnings sharing for 2005 per the annual compliance filings by NYSEG and RG&E.

Those increases were partially offset by:

• A decrease of $26 million resulting from reduced sales under the companies' commodity programs,
• A decrease of $16 million resulting from lower retail deliveries due largely to warmer winter weather, and
• A decrease of $30 million in average delivery prices resulting from lower transition charges. This charge decreases as market prices increase.

Operating Expenses: The $56 million increase in operating expenses for the six months ended June 30, 2006, was primarily the result of:

• An increase of $18 million in purchased power costs resulting from $46 million for higher wholesale electricity market prices, reduced by $28 million due to the expiration of a major NUG contract in 2006,
• An increase of $28 million in operating and maintenance costs including $9 million for storm restoration, $13 million for higher uncollectible reserves and $4 million related to NYSEG's rate case,
• An increase of $4 million in depreciation resulting largely from the implementation of NYSEG's new customer care system, and
• An increase of $5 million in other taxes primarily due to a refund received in 2005.

Operating Revenues: The $1 million increase in operating revenues for the second quarter of 2006 was primarily the result of:

• An increase of $6 million as a result of higher market prices of natural gas, and
• An increase of $3 million as a result of higher base rates for SCG effective January 1, 2006.

Those increases were partially offset by:

• A decrease of $5 million in delivery volumes due to warmer weather and customer conservation, and
• A decrease of $3 million in other revenue.

Operating Expenses: The $10 million increase in operating expenses for the second quarter of 2006 was primarily the result of:

• An increase of $5 million due to higher market prices for purchased natural gas, and
• An increase of $7 million in operating and maintenance costs including $12 million for higher uncollectible reserves, partially offset by reductions for various other items.

Those increases were partially offset by:

• A decrease of $2 million in other taxes.

Operating Revenues: The $36 million increase in operating revenues for the six months ended June 30, 2006, was primarily the result of:

• An increase of $127 million primarily as a result of higher natural gas market prices that were passed on to customers, and
• An increase of $13 million due to higher base rates for SCG effective January 1, 2006.

Those increases were partially offset by:

• A decrease of $103 million as a result of lower delivery volumes due largely to warmer winter weather and customer conservation.

Operating Expenses: The $43 million increase in operating expenses for the six months ended June 30, 2006, was primarily the result of:

• An increase of $105 million due to higher market prices for purchased natural gas, and
• An increase of $6 million in operating and maintenance costs including $11 million for higher uncollectible reserves, partially offset by a decrease of $5 million for various other items.

Those increases were partially offset by:

• A reduction of $69 million due to lower volumes of natural gas purchases.