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 October 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,
• implementation of the NYPSC's Order in NYSEG's Electric Rate Plan Extension proceeding,
• 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's natural gas segment, 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. Where long-term rate plans are not in effect, we monitor the adequacy of rate levels and file for new rates when necessary. NYSEG's current electric rate plan expires December 31, 2006, and new rates will go into effect in 2007. SCG received approval for new rates that became effective January 1, 2006, and CNG recently filed for new rates.

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 implemented a similar system in October 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 and rates that our customers pay for energy, 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. The $900 million includes $260 million for CMP's five-year construction plan to enhance transmission reliability and service. We expect those investments will be FERC-regulated and we expect them to qualify for FERC's ROE incentive adders. (See New England RTO.) 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 nine months ended September 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 are 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 presently 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. However, the NYPSC recently denied our proposal to extend the long-term rate plan for NYSEG's electric segment, and approved a one-year rate plan that will reduce NYSEG's earnings in 2007 and limit NYSEG's ability to offer customer options for supply in 2007 and beyond. (See NYSEG Electric Rate Order 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 Order: 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. NYSEG's Electric Rate Plan Extension, as subsequently amended, proposed, beginning on January 1, 2007, to reduce the nonbypassable wires charge by $168 million and increase delivery rates by $104 million, thereby resulting in an annualized overall electricity delivery rate decrease of $64 million, or 8.6%. NYSEG proposed to accomplish the reduction in its nonbypassable wires charge 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%. Staff neither rebutted nor addressed NYSEG's revised and updated rate plan extension proposal, including its NUG levelization proposal and opposed NYSEG's proposal to extend its Voice Your Choice program. Staff also raised several retroactive accounting issues that will be addressed in a future proceeding and, if accepted by the NYPSC, would have a material effect on earnings.

On August 23, 2006, the NYPSC issued the Order, which included the following provisions:

• A decrease in delivery rates of $36 million. NYSEG's most recent update in the proceeding requested a $58 million increase in delivery rates.

• A 9.55% ROE. NYSEG had requested an 11% ROE.

• An equity ratio of 41.6% based on Energy East's consolidated capital structure. NYSEG had requested a 50% equity ratio based on its stand-alone capital structure.

• A refund of $77 million to be paid from NYSEG's ASGA and will not affect earnings. The ASGA was initially created as a result of the sale of NYSEG's generating stations and has been enhanced during NYSEG's current electric rate plan with the customers' share of earnings from the earnings sharing mechanism. Payment of the refund is expected to be made through a credit to customers' bills in the first quarter of 2007.

• One issue raised by Staff concerns $57 million of interest associated with NYSEG's internal other post employment benefits (OPEB) reserve, which NYSEG has offset against other OPEB costs in its income statement over the past decade. The NYPSC determined that $3.6 million in annual revenues that NYSEG receives will remain temporary pending further examination of the NYSEG's accounting for OPEB costs. A proceeding related to this issue will begin in the fourth quarter of 2006 and could result in NYSEG treating all or a portion of the $57 million as an addition to its internal OPEB reserve, with a corresponding charge to income.

• Significant modifications to NYSEG's commodity options program, including:

NYSEG believes that the commodity options program in the Order is unworkable and inconsistent with the development of a competitive retail market for supply. In particular, NYSEG believes that the lower allowance used to set the supply rate does not cover the cost and risk of providing fixed price electricity at retail and will likely stifle participation by retail energy service providers.

The Order will have a significant adverse effect on NYSEG's financial condition and results of operations. NYSEG believes that the Order provides an inadequate ROE and ignored millions of dollars of forecasted expenses, which will force NYSEG to adjust operating, maintenance and capital spending, and is likely to result in workforce reductions and degradation in current levels of customer service. It also excludes from rate base $8.5 million of costs related to system implementation to facilitate integration activities, which treatment, if upheld, would require an impairment of these assets. Any impairment would be partially offset by lower accruals under the earnings sharing mechanism.

On September 7, 2006, NYSEG filed a petition with the NYPSC for rehearing and request for oral argument responding to certain aspects of the Order including the disallowance of system implementation costs. NYSEG is also considering an appeal to a state appellate court and filing a new electric rate case in 2007.

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 substantially all incremental operating and maintenance costs, net of insurance proceeds, resulting from the flooding. As of September 2006, NYSEG's costs incurred to recover from the flood were $8 million, of which $6 million was deferred for future recovery.

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 was contingent upon the fulfillment of certain closing conditions, including FERC acceptance of an amendment to and restatement of the exit agreement. All of the necessary closing conditions were fulfilled, including a favorable judgement from the FERC, and RG&E made the required payment. 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 adjusted its regulatory asset established as a result of the sale of NMP2 for the amount of the $34 million payment to Niagara Mohawk, which was offset by the accumulated TCC amount of approximately $4 million and will be adjusted by any future TCC amounts. RG&E's results of operations were not affected by the settlement of this dispute.

Threatened Litigation for Russell Station: In October 1999 RG&E received a letter from the New York State Attorney General's office alleging that RG&E may have constructed and operated major modifications to the Beebee and Russell generating stations without obtaining the required prevention of significant deterioration or new source review permits. The letter requested that RG&E provide the Attorney General's office with a large number of documents relating to this allegation. In January 2000 RG&E received a subpoena from the NYSDEC ordering production of similar documents. RG&E supplied documents and complied with the subpoena.

The NYSDEC served RG&E with a notice of violation in May 2000 alleging that between 1983 and 1987 RG&E completed five projects at Russell Station, scheduled to be shut down in 2007, and two projects at Beebee Station, which is currently shut down, without obtaining the appropriate permits. RG&E believes it has complied with the applicable rules and there is no basis for the Attorney General's and the NYSDEC's allegations. Beginning in July 2000 the NYSDEC, the Attorney General and RG&E had a number of discussions with respect to the resolution of the notice of violation. RG&E, the NYSDEC and the Attorney General last discussed this matter in August 2005. In October 2006 the Attorney General's office and the NYSDEC notified RG&E of their intention to file a complaint in federal court for violations at Russell Station unless a settlement can be reached. RG&E is not able to predict the outcome of this matter.

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 an aggregate of over 360 MWs of Niagara Power Project power has been allocated to the companies 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 other than the portion that was implemented. 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.

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. On August 11, 2006, Connecticut Yankee filed a Settlement Agreement supported by all parties, including the FERC trial staff, that resolved all of the issues contested and will allow Connecticut Yankee to collect the increased decommissioning costs. The revised decommissioning charges will be collected in wholesale rates effective January 1, 2007, until December 2015. FERC approval of the Settlement Agreement is pending.

On September 30, 2006, the U.S. Court of Federal Claims issued a favorable ruling for the three Yankee companies in their litigation with the federal government over its failure to remove spent nuclear fuel from the three former nuclear power plant sites. In the ruling, Yankee Atomic was awarded $33 million in damages for costs through 2001, Connecticut Yankee was awarded $34 million for costs through 2001, and Maine Yankee was awarded $76 million for costs through 2002. CMP's sponsor-weighted share of the award is approximately $34 million. Since spent nuclear fuel continues to be stored at the sites, the Yankee companies will have the opportunity to recover more damages in future lawsuits. The federal government is expected to appeal the decision, which would delay any damage awards. Any awards ultimately received would be credited to the Yankee companies' respective electric ratepayer-funded, decommissioning or spent fuel trust funds. CMP cannot predict the ultimate outcome of this matter.

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 what NYSEG and RG&E believe are 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 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. On September 1, 2006, RG&E filed its proposal for the ESCO referral plan parameters. The NYPSC required NYSEG to implement an ESCO Referral Program as part of its Order in the electric rate plan extension proceeding described above. NYSEG filed its proposal for the ESCO referral program parameters on October 23, 2006. (See NYSEG Electric Rate Order.)

New England RTO: In March 2004 the FERC issued an order that accepted a six-state New England RTO as proposed by ISO-NE and the New England transmission owners. The RTO began operations effective February 1, 2005. As an RTO, ISO-NE is responsible for the independent operation of the regional transmission system and regional wholesale energy market. The transmission owners retain ownership of their transmission facilities and control over their revenue requirements. The FERC also approved both a 50 basis point ROE incentive adder for regional transmission facilities subject to RTO control and a 100 basis point ROE incentive adder for new regional transmission facilities developed by an RTO. The New England transmission owners appealed the application of the adders to local facilities to the Circuit Court of Appeals for the District of Columbia. Other parties appealed the FERC's decision to grant the adders to regional facilities. On June 30, 2006, the Court denied the appeals and upheld the FERC's decisions. On October 31, 2006, the FERC issued an Opinion and Order on Initial Decision establishing the ROE applicable to the RTO, including CMP's transmission system. The October 31 Order adopts a base-level ROE of 10.2 percent, with three adjustments as follows: a 50 basis point incentive for RTO participation; a 100 basis point incentive for new transmission investment; and, a 74 basis point adjustment reflecting updated bond data, as applicable to the period commencing with the date of the Order. The resulting ROEs for existing transmission are 10.7 percent for the period February 1, 2005 through October 31, 2006 and 11.4 percent for the going-forward period. The ROEs that will apply to new transmission include the 100 basis point adjustment and are 11.7 percent prior to the date of the Order and 12.4 percent for the going-forward period. Parties can seek rehearing within 30 days of the Order and can appeal the final Order. The Company cannot predict the outcome of these proceedings. (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.)

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. 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 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. On October 31, 2006, the FERC issued an Order on Rehearing and Clarification denying requests for rehearing and affirming its approval of the settlement agreement. Parties can appeal the FERC order and CMP cannot predict the outcome of these proceedings.

MPUC Inquiries into Long-Term Utility Contracting 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 September 29, 2006, CNG submitted a general rate filing, requesting a net rate increase of $28.2 million, or 7.9%, in base delivery revenues effective April 1, 2007, based on an 11.0% ROE. The requested increase includes $6.7 million for increased bad debt expense, including a hardship program, $5.6 million for sharing of achieved management efficiencies and $4.3 million to offset lower normalized customer usage.

The FASB released FIN 48 in July 2006 and issued Statements 157 and 158 in September 2006. See Item 1, Note 8 to our financial statements for information concerning the new accounting standards.

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

• A reduction in accounts payable of $258 million that reduced cash primarily due to payments for natural gas and electricity purchases,
• Decreased receivables that increased cash by $241 million,
• Payments of $169 million to counterparties in derivative contracts representing both refunds of amounts held at year end and current collateral obligations, and
• The payment of $34 million by RG&E to resolve a dispute with Niagara Mohawk. (See RG&E Dispute Settlement Related to NMP2 Exit Agreement.)

The Order in NYSEG's electric rate case requires a $77 million refund to customers funded from the ASGA. That refund is currently expected to be paid as bill credits in the first quarter of 2007. Other aspects of the Order will reduce earnings and, therefore cash flow, and may affect NYSEG's credit ratings and increase its costs of borrowing, but should not have other effects on liquidity.

Investing Activities: Capital spending for the nine months ended September 30, 2006, was $267 million. We project capital spending of $442 million in 2006, including $53 million for an RG&E transmission project, and expect to pay for it principally with internally generated funds. (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, RG&E Transmission Project.) Capital spending is primarily for the extension of energy delivery service, necessary improvements to existing facilities, and compliance with environmental requirements and governmental mandates, and includes the transmission project and a new customer care system.

Cash flows from investing activities include proceeds from the liquidation of auction rate securities which are recorded as current investments available for sale. We use auction rate securities in a manner similar to cash equivalents and the amount invested in such securities will increase as short-term funds are available. Our investments in auction rate securities have decreased during the year as a result of the operational activities discussed above.

Financing Activities: The financing activities discussed below include those activities necessary for us and our principal subsidiaries to maintain adequate liquidity and 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 the nine months ended September 30, 2006, we awarded 272,733 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 $24.75 per share of common stock awarded.

Beginning in the fourth quarter of 2005 and continuing through the third quarter of 2006, instead of issuing new shares, we purchased shares of our common stock in the open market for dividends reinvested and optional cash purchases through our Investor Services Program (ISP). Therefore, during the nine months ended September 30, 2006, cash outflows for dividends equal the amount of our dividends as shown on our retained earnings statement. In the fourth quarter of 2006, we resumed issuing new shares through our ISP.

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 Statement 158 would have on total capitalization, which requires that unrecognized postretirement costs be recognized as components of other comprehensive income. 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 August 2006 we issued an additional $250 million of unsecured long-term debt at 6.75% due in 2036. We used substantially all of the proceeds to redeem $232 million of 5.75% notes that were scheduled to mature in November 2006. In August 2006 we settled the hedges we had entered into in connection with the refinancing at a gain of approximately $8 million, which we will amortize over the life of the new debt.

In October 2006 we raised our common stock dividend 3.4% to a new annual rate of $1.20 per share.

Three Months: Earnings per share for the quarter ended September 30, 2006, were unchanged compared to the quarter ended September 30, 2005. The recognition of unamortized debt expenses related to the redemption of our 8 1/4% junior subordinated debt securities in July 2006 reduced earnings by 5 cents per share. That decrease was offset by lower income tax expense of 5 cents per share reflecting actual 2005 tax expense as filed, revisions to estimated 2006 tax expense and settlement of an audit of our 2002 and 2003 federal income tax returns.

Nine Months: Earnings per share for the nine months ended September 30, 2006, decreased 7 cents compared to the nine months ended September 30, 2005, primarily because of:

• A decrease of 11 cents per share resulting from higher uncollectible reserves (reflecting both an increase in 2006 and the effect of a decrease in 2005),
• A decrease of 6 cents per share for higher interest expense resulting from higher rates on short-term and variable rate debt, higher debt balances and higher carrying costs on regulatory liabilities,
• The recognition of unamortized debt expense of 5 cents per share resulting from the redemption of our 8 1/4% junior subordinated debt securities in July 2006, and

• A decrease of 5 cents per share resulting from increased depreciation expense and other taxes. The depreciation increase was primarily due to placing NYSEG's customer care system into service in the first quarter of 2006.

Those decreases were partially offset by:

• An increase of 12 cents per share due to higher margins on electricity sales, primarily reflecting lower accruals under various earnings sharing mechanisms, and
• A decrease in tax expense of 5 cents per share, as discussed above.

Three Months

Operating Revenues: The $3 million increase in operating revenues for the third quarter of 2006 was primarily the result of:

• An increase of $13 million due to higher prices for retail electric energy sold by NYSEG and RG&E under various commodity options where they provide supply,
• An increase of $29 million resulting from lower accruals for earnings sharing which is included in other revenues, and
• An increase of $51 million in average prices for delivery resulting primarily from lower transition charges. The transition charge reflects the difference between the market price of electricity and the prices of our long-term electricity contracts, and increases as market prices decrease.

Those increases were partially offset by:

• A decrease of $45 million resulting from an 8% decline in electricity sales under NYSEG's and RG&E's commodity programs,
• A decrease of $21 million in wholesale sales reflecting both an 8% decline in volume and lower wholesale prices, and
• A decrease of $14 million resulting from a 7% decline in retail deliveries from 2005 levels. Approximately 2% of the 7% decrease was due to cooler temperatures as there were 21% fewer cooling degree days in New York and 11% fewer in Maine compared to the prior year. In addition, about 1% of the decline was attributable to the expiration of a major NUG contract for CMP at the end of 2005. Energy previously sold to CMP is now retained and used by the NUG for its own load requirements. Another 3% of the decline was attributable to an adjustment that increased unbilled revenues in the third quarter of 2005.

Operating Expenses: The $3 million increase in operating expenses for the third quarter of 2006 was primarily the result of:

• An increase of $3 million for higher purchased power costs, which was net of a $14 million reduction due to the expiration of a major NUG contract for CMP, and
• An increase of $3 million in depreciation primarily due to placing NYSEG's customer care system into service in the first quarter of 2006.

Those increases were partially offset by:

• A decrease of $3 million due to various operating and maintenance expense items.

Nine Months

Operating Revenues: The $51 million increase in operating revenues for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $40 million in wholesale revenue resulting from a 5% increase in wholesale volumes and higher wholesale market prices,
• An increase of $43 million due to higher prices for retail electric energy sold by NYSEG and RG&E under various commodity options where they provide supply,
• An increase of $40 million in average delivery prices resulting from higher transition charges, and
• An increase of $50 million resulting from lower accruals for earnings sharing including $14 million in the first quarter of 2006 for the finalization of actual earnings sharing amounts for 2005 per NYSEG's and RG&E's annual compliance filings.

Those increases were partially offset by:

• A decrease of $71 million resulting from a 6% reduction in sales volume under the companies' commodity programs,
• A decrease in other revenue of $18 million including $6 million related to a NUG incentive CMP recorded in 2005. The remainder is primarily for accruals to reconcile to actual purchased power costs, and

• A decrease of $32 million resulting from a 3% decline in retail deliveries, about 1% of which is weather related. In addition to the cooler summer temperatures described above, warmer winter weather contributed to the decline in sales volume. Year-to-date heating degree days declined by 11% in New York and 13% in Maine from 2005 levels. In addition, about 1% of the decline was attributable to the expiration of a major NUG contract for CMP. Another 1% of the decline was attributable to an adjustment that increased unbilled revenues in the third quarter of 2005.

Operating Expenses: The $59 million increase in operating expenses for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $21 million in purchased power costs resulting from a $63 million increase for higher wholesale electricity market prices, partially offset by a $42 million decrease due to the expiration of a major NUG contract in 2006,
• An increase of $25 million in operating and maintenance costs, including $9 million for storm restoration, $14 million for higher bad debt expense, including uncollectible reserves, and $4 million related to costs incurred for NYSEG's rate case,
• An increase of $7 million in depreciation resulting largely from NYSEG's new customer care system, and
• An increase of $7 million in other taxes primarily due to a refund received in 2005.

Three Months

Operating Revenues: Operating revenues for the third quarter of 2006 decreased less than $1 million. The decrease was the result of:

• A decrease of $7 million as a result of lower market prices for natural gas that were passed on to customers, and
• A decrease of $5 million in other revenues.

That decrease was partially offset by:

• An increase of $9 million resulting from a 6% increase in delivery volumes, and
• An increase of $2 million due to higher base rates at SCG effective January 1, 2006.

Operating Expenses: The $5 million decrease in operating expenses for the third quarter of 2006 was primarily the result of:

• A decrease of $9 million due to lower market prices for purchased natural gas.

That decrease was partially offset by:

• An increase of $3 million related to higher delivery volumes, and
• An increase of $2 million in operating and maintenance expense, including $4 million for increased bad debt expense.

Nine Months

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

• An increase of $120 million primarily as a result of higher market prices for natural gas that were passed on to customers, and
• An increase of $14 million due to higher base rates for SCG effective January 1, 2006.

Those increases were partially offset by:

• A decrease of $96 million as a result of a 9% decrease in delivery volumes, largely due to warmer winter weather and customer conservation. Through the third quarter of 2006 heating degree days declined 11% compared to the same period in 2005 and caused approximately 7% of the sales decline, and
• A decrease of $3 million in other revenue.

Operating Expenses: The $38 million increase in operating expenses for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $99 million due to higher market prices for purchased natural gas, and
• An increase of $8 million in operating and maintenance costs including $14 million for higher bad debt expense, partially offset by a decrease of $4 million for lower payroll and benefit costs and $2 million for various other items.

Those increases were partially offset by:

• A reduction of $68 million due to lower volumes of natural gas sold.