UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2006

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934
      For the transition period from             to

Commission file number	Exact name of Registrant as specified in its charter, State of incorporation, Address and Telephone number	IRS Employer Identification No.
1-14766	Energy East Corporation (AIncorporated in New York ~~Corporation~~) P.52 O.Farm ~~Box~~View ~~12904~~Drive ~~Albany,~~ New ~~York~~Gloucester, ~~12212~~Maine 04260-~~2904~~5116 (~~518~~207) ~~434~~688-~~3049~~6300 www.energyeast.com	14-1798693
1-5139	Central Maine Power Company (A Maine Corporation) 83 Edison Drive Augusta, Maine 04336 (207) 623-3521	01-0042740
1-672	Rochester Gas and Electric Corporation (Incorporated in New York) 89 East Avenue Rochester, New York 14649 (585) 546-2700	16-0612110
1-3103-2	New York State Electric & Gas Corporation (A New York Corporation) P. O. Box 5224 Binghamton, New York 13902-5224 (607) 762-7200	15-0398550
1-672	Rochester Gas and Electric Corporation (A New York Corporation) 89 East Avenue Rochester, New York 14649 (585) 546-2700	16-0612110

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, ~~(as~~or ~~defined~~a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act). (Check one):

Registrant ~~Energy~~Large ~~East~~accelerated ~~Corporation~~filer ~~Yes~~Accelerated Xfiler NoNon-accelerated ~~Central~~filer ~~Maine~~Energy ~~Power~~East ~~Company Yes No X New York State Electric & Gas~~ Corporation ~~Yes No~~ X Rochester Gas and Electric Corporation ~~Yes No~~ X

AsIndicate ofby ~~July~~check ~~31,~~mark ~~2004,~~whether ~~shares~~the ofregistrant ~~common~~is ~~stock~~a ~~outstanding~~shell ~~for~~company ~~each~~(as ~~registrant~~defined ~~were:~~in Rule 12b-2 of the Exchange Act).

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	146,706,572
Central Maine Power Company	Par value $5 per share	31,211,471 (1)
New York State Electric & Gas Corporation	Par value $6.66 2/3 per share	64,508,477 (2)
Rochester Gas and Electric Corporation	Par value $5 per share	34,506,513 (2)

Registrant	Yes	No
Energy East Corporation		X
Rochester Gas and Electric Corporation		X

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

As of April 28, 2006, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	147,678,358
Rochester Gas and Electric Corporation	Par value $5 per share	34,506,513 ⁽¹⁾

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

This combined Form 10-Q is separately filed by Energy East Corporation, ~~Central Maine Power Company, New York State Electric & Gas Corporation~~ and Rochester Gas and Electric Corporation. Information contained herein relating to ~~any~~either ~~individual~~ registrant is filed by such registrant on its own behalf. ~~Each~~Neither registrant makes noany representation as to information relating to the other ~~registrants~~registrant.

Item	TABLE OF CONTENTS	Page
	Table of Contents	Page
	Glossary	ii
	Forward-looking Statements	iv
	PART I - FINANCIAL INFORMATION
1 2	Financial Statements Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 1. Item 2.	Financial Statements Management's Discussion and Analysis of Financial Condition and Results of Operations
	Energy East Corporation Condensed Consolidated Statements of Income Condensed Consolidated Balance Sheets Condensed Consolidated Statements of Cash Flows Condensed Consolidated Statements of Retained Earnings Condensed Consolidated Statements of Comprehensive Income Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	1 2 4 5 5 6 1612 14
	Central Maine Power Company Condensed Consolidated Statements of Income Condensed Consolidated Balance Sheets Condensed Consolidated Statements of Cash Flows Condensed Consolidated Statements of Retained Earnings Condensed Consolidated Statements of Comprehensive Income Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	19 20 22 22 22 23 24
	Rochester Gas and Electric Corporation Condensed Balance Sheets Condensed Statements of Income Condensed Statements of Cash Flows Condensed Statements of Retained Earnings Condensed Statements of Comprehensive Income Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	16 18 19 20 20 21 22
	New York State Electric & Gas Corporation Condensed Statements of Income Condensed Balance Sheets Condensed Statements of Cash Flows Condensed Statements of Retained Earnings Condensed Statements of Comprehensive Income Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	25 26 28 29 29 30 31
	Notes to Condensed Financial Statements	24
	Rochester Gas and Electric Corporation Condensed Statements of Income Condensed Balance Sheets Condensed Statements of Cash Flows Condensed Statements of Retained Earnings Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	33 34 36 36 37 38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	30
	PART II - OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 6.	Exhibits	31
Signatures		32
Exhibit Index		33

Item TABLE OF CONTENTS - continued Page
1 Notes to Condensed Financial Statements Forward-looking Statements 41 52
3 Quantitative and Qualitative Disclosures About Market Risk 53
4 Controls and Procedures 54
PART II - OTHER INFORMATION
2 Changes in Securities, Use and Proceeds and Issuer Purchases of Equity Securities 54
4 Submission of Matters to a Vote of Security Holders 56
6 Exhibits and Reports on Form 8-K (a) Exhibits (b) Reports on Form 8-K 57
Signatures 58
Exhibit Index 59
Glossary

Abbreviations for the Energy East companies mentioned in this report:
Berkshire Gas The Berkshire Gas Company is a regulated utility primarily engaged in the distribution of natural gas in western Massachusetts. CMP Central Maine Power Company is a regulated utility primarily engaged in transmitting and distributing electricity generated by others to retail customers in Maine. CNG Connecticut Natural Gas Corporation is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut. Energy East, the company, we, our or us Energy East Corporation is the parent company of RGS Energy Group, Inc., Connecticut Energy Corporation, CMP Group, Inc., CTG Resources, Inc., Berkshire Energy Resources, The Energy Network and Energy East Enterprises.	NYSEG New York State Electric & Gas Corporation is a regulated utility primarily engaged in purchasing and delivering electricity and natural gas in the central, eastern and western parts of the state of New York. RG&E Rochester Gas and Electric Corporation is a regulated utility primarily engaged in generating, purchasing and delivering electricity and purchasing and delivering natural gas in an area centered around the city of Rochester, New York. SCG The Southern Connecticut Gas Company is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut.

Abbreviations or acronyms frequently used in this report:
AFUDC allowance for funds used during construction ALJ Administrative Law Judge APB 25 Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ARP 2000 Alternative Rate Plan 2000 ASGA Asset Sale Gain Account Dth dekatherm DPUC Connecticut Department of Public Utility Control Electric Rate Agreement Electric portion of RG&E's 2004 Electric and Natural Gas Rate Agreements EPS earnings per share ESCO energy service company	ESCO energy service company FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission Ginna Robert E. Ginna Nuclear Power Plant, a nuclear power plant sold by RG&E in June 2004 IRP Incentive Rate Plan ISO-NE ISO New England Inc. LICAP locational installed capacity (pricing mechanism in the New England market as currently proposed) MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations MPUC Maine Public Utilities Commission MW, MWh megawatt, megawatt hour

Glossary (continued)

NEPOOL
New England Power Pool

NUG nonutility generator

NYISO New York Independent
System Operator

NYPA New York Power Authority

NYPSC New York State Public
Service Commission

OCC The Office of Consumer Counsel
in the State of Connecticut

Policy Statement NYPSC Statement of
Policy on Further Steps Toward Competition
in Retail Energy Markets

RTO Regional Transmission Organization

SARs stock appreciation rights

SEC United States Securities and
Exchange Commission

Statement 123 Statement of Financial
Accounting Standards No. 123, Accounting
for Stock-Based Compensation

Statement 123(R) Statement of Financial
Accounting Standards No. 123 (revised 2004), Shared-Based Payment

Voice Your Choice RG&E's and NYSEG's electric commodity option programs

Forward-looking Statements

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,
enactment and 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 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 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.

PART I - FINANCIAL INFORMATION
Item 1.
Financial Statements

Energy East Corporation Condensed Consolidated Statements of Income - (Unaudited)
	Three Months		Six Months
Three months ended March 31,	2006	2005
Periods ended June 30	2004	2003	2004	2003
(Thousands, except per share amounts)
(Thousands, except per share amounts)
Operating Revenues
Operating Revenues
Utility	$1,542,205	$1,489,519
Sales and services	$980,566	$979,113	$2,561,639	$2,483,944
Nonutility	154,349	147,759
Operating Expenses
Total Operating Revenues	1,696,554	1,637,278
Electricity purchased and fuel used in generation	338,253	300,967	734,906	659,334
Operating Expenses
Natural gas purchased	169,700	178,414	669,549	629,465
Electricity purchased and fuel used in generation
Other operating expenses	158,065	199,916	372,072	394,539
Utility	377,342	356,262
Maintenance	42,814	43,309	85,476	89,556
Nonutility	89,389	80,929
Depreciation and amortization	84,799	73,774	169,934	149,107
Natural gas purchased
Other taxes	58,248	58,382	133,670	143,649
Utility	509,769	475,951
Gain on sale of generation assets	(319,487)	-	(319,487)	-
Nonutility	43,774	43,179
Deferral of asset sale gain	214,368	-	214,368	-
Other operating expenses	186,106	181,673
Total Operating Expenses	746,760	854,762	2,060,488	2,065,650
Maintenance	52,464	42,515
Operating Income	233,806	124,351	501,151	418,294
Depreciation and amortization	69,404	67,921
Other (Income)	(11,681)	(2,278)	(17,409)	(6,810)
Other taxes	73,865	68,031
Other Deductions	4,398	1,261	7,675	3,048
Total Operating Expenses	1,402,113	1,316,461
Interest Charges, Net	68,822	68,090	138,812	135,825
Operating Income	294,441	320,817
Preferred Stock Dividends of Subsidiaries	1,791	8,739	2,779	17,157
Other (Income)	(10,400)	(7,824)
Income From Continuing Operations Before Income Taxes	170,476	48,539	369,294	269,074
Other Deductions	4,017	1,975
Income Taxes	127,694	20,206	205,803	109,050
Interest Charges, Net	78,720	69,736
Income From Continuing Operations	42,782	28,333	163,491	160,024
Preferred Stock Dividends of Subsidiaries	282	476
Discontinued Operations
Income Before Income Taxes	221,822	256,454
(Loss) income from discontinued operations	(4,249)	(901)	(4,527)	5,058
Income Taxes	88,581	102,088
Income taxes (benefits)	467	(285)	346	1,901
Net Income	$133,241	$154,366
(Loss) Income From Discontinued Operations	(4,716)	(616)	(4,873)	3,157
Earnings per Share, basic	$.91	$1.05
Net Income	$38,066	$27,717	$158,618	$163,181
Earnings per Share, diluted	$.90	$1.05
Earnings Per Share From Continuing Operations, basic	$.29	$.19	$1.12	$1.10
Dividends Paid per Share	$.29	$.275
Earnings Per Share From Continuing Operations, diluted	$.29	$.19	$1.11	$1.10
Average Common Shares Outstanding, basic	147,034	146,875
Earnings Per Share From Discontinued Operations, basic	$(.03)	-	$(.03)	$.02
Average Common Shares Outstanding, diluted	147,679	147,196
Earnings Per Share From Discontinued Operations, diluted	$(.03)	-	$(.03)	.02
Total Earnings Per Share, basic	$.26	$.19	$1.09	$1.12
Total Earnings Per Share, diluted	$.26	$.19	$1.08	$1.12
Dividends Paid Per Share	$.26	$.25	$.52	$.50
Average Common Shares Outstanding, basic	146,148	145,415	146,116	145,256
Average Common Shares Outstanding, diluted	146,596	145,640	146,512	145,429

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$461,059	$113,187
Special deposits	7,273	34,669
Accounts receivable, net	600,846	753,328
Fuel, at average cost	124,803	159,163
Materials and supplies, at average cost	24,321	22,491
Accumulated deferred income tax benefits, net	38,289	26,262
Prepayments and other current assets	69,366	81,746
Total Current Assets	1,325,957	1,190,846
Utility Plant, at Original Cost
Electric	5,209,400	5,992,001
Natural gas	2,453,826	2,405,795
Common	408,831	361,737
	8,072,057	8,759,533
Less accumulated depreciation	2,523,200	3,216,927
Net Utility Plant in Service	5,548,857	5,542,606
Construction work in progress	69,042	235,503
Total Utility Plant	5,617,899	5,778,109
Other Property and Investments, Net	190,382	465,609
Regulatory and Other Assets
Regulatory Assets
Nuclear plant obligations	379,367	414,432
Unfunded future income taxes	114,542	254,977
Unamortized loss on debt reacquisitions	48,595	47,509
Environmental remediation costs	122,662	122,846
Nonutility generator termination agreements	101,395	106,631
Asset retirement obligation	-	163,530
Other	397,594	407,432
Total regulatory assets	1,164,155	1,517,357
Other Assets
Goodwill, net	1,527,169	1,533,123
Prepaid pension benefits	637,170	608,933
Other	205,296	212,455
Total other assets	2,369,635	2,354,511
Total Regulatory and Other Assets	3,533,790	3,871,868
Total Assets	$10,668,028	$11,306,432

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003
(Thousands)
Liabilities
Current Liabilities
Current portion of preferred stock of subsidiary subject to mandatory redemption requirements	-	$1,250
Current portion of long-term debt	$24,711	30,989
Notes payable	31,201	308,406
Accounts payable and accrued liabilities	390,469	339,812
Interest accrued	47,395	48,989
Taxes accrued	118,666	43,710
Other	136,869	191,873
Total Current Liabilities	749,311	965,029
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	735,879	731,621
Deferred income taxes	14,858	181,211
Gain on sale of generation assets	238,887	129,640
Pension benefits	31,728	51,970
Other	123,878	96,509
Total regulatory liabilities	1,145,230	1,190,951
Other liabilities
Deferred income taxes	947,843	853,489
Nuclear plant obligations	265,022	277,643
Other postretirement benefits	424,817	408,903
Asset retirement obligation	3,049	437,076
Environmental remediation costs	147,897	145,446
Other	365,769	346,630
Total other liabilities	2,154,397	2,469,187
Total Regulatory and Other Liabilities	3,299,627	3,660,138
Debt owed to subsidiary holding solely parent debentures	355,670	355,670
Preferred stock of subsidiary subject to mandatory redemption requirements	-	23,750
Other long-term debt	3,552,011	3,638,426
Total long-term debt	3,907,681	4,017,846
Total Liabilities	7,956,619	8,643,013
Commitments	-	-
Preferred Stock of Subsidiaries Redeemable solely at the option of subsidiaries	46,624	91,095
Common Stock Equity Common stock	1,467	1,463
Capital in excess of par value	1,464,528	1,458,802
Retained earnings	1,209,131	1,126,457
Accumulated other comprehensive income (loss)	(2,931)	(11,214)
Deferred compensation	(6,765)	(2,820)
Treasury stock, at cost	(645)	(364)
Total Common Stock Equity	2,664,785	2,572,324
Total Liabilities and Stockholders' Equity	$10,668,028	$11,306,432

The

notes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
Six months ended June 30	2004	2003
	March 31, 2006	Dec. 31, 2005
(Thousands)
Net Cash Provided by Operating Activities	$405,808	$377,971
Assets
Investing Activities
Current Assets
Proceeds from sale of generation assets	428,541	-
Cash and cash equivalents	$178,989	$120,009
Refund of excess decommissioning fund	76,593	-
Investments available for sale	11,575	192,925
Utility plant additions	(123,554)	(112,955)
Accounts receivable and unbilled revenues, net	1,040,382	933,680
Other property and investments additions	(2,045)	(13,631)
Fuel and natural gas in storage, at average cost	125,972	278,590
Other property and investments sold	7,957	5,054
Materials and supplies, at average cost	34,397	33,886
Special deposits	27,396	(81,134)
Deferred income taxes	18,711	-
Other	(3,501)	(2,377)
Derivative assets	94,125	278,855
Net Cash Provided (Used) in Investing Activities	411,387	(205,043)
Prepayments and other current assets	126,094	92,613
Financing Activities
Total Current Assets	1,630,245	1,930,558
Issuance of common stock	1,252	2,466
Utility Plant, at Original Cost
Repurchase of common stock	(6,071)	-
Electric	5,430,210	5,403,134
Outstanding customer refund, overdraft	57,388	-
Natural gas	2,585,112	2,574,574
Repayments of first mortgage bonds and preferred stock of subsidiaries, including net premiums	(162,053)	(115,270)
Common	535,321	450,641
Long-term note issuances	12,000	196,986
	8,550,643	8,428,349
Long-term note repayments	(12,778)	(6,140)
Less accumulated depreciation	2,841,517	2,764,399
Notes payable three months or less, net	(279,203)	(128,700)
Net Utility Plant in Service	5,709,126	5,663,950
Notes payable issuances	3,000	-
Construction work in progress	47,935	119,504
Notes payable repayments	(16,000)	(91,435)
Total Utility Plant	5,757,061	5,783,454
Dividends on common stock	(66,858)	(63,803)
Other Property and Investments	199,300	203,159
Net Cash Used in Financing Activities	(469,323)	(205,896)
Regulatory and Other Assets
Net Increase (Decrease) in Cash and Cash Equivalents	347,872	(32,968)
Regulatory assets
Cash and Cash Equivalents, Beginning of Period	113,187	250,490
Deferred income taxes	-	13,482
Cash and Cash Equivalents, End of Period	$461,059	$217,522
Nuclear plant obligations	294,777	309,888
Unfunded future income taxes	177,984	117,241
Environmental remediation costs	136,533	135,376
Unamortized loss on debt reacquisitions	58,831	60,933
Nonutility generator termination agreements	87,310	86,890
Other	329,436	384,173
Total regulatory assets	1,084,871	1,107,983
Other assets
Goodwill, net	1,525,353	1,525,353
Prepaid pension benefits	748,169	741,831
Derivative assets	59,773	67,907
Other	122,164	127,463
Total other assets	2,455,459	2,462,554
Total Regulatory and Other Assets	3,540,330	3,570,537
Total Assets	$11,126,936	$11,487,708

Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Six months ended June 30	2004	2003
(Thousands)
Balance, Beginning of Period	$1,126,457	$1,061,428
Add net income	158,618	163,181
Deduct dividends on common stock	75,944	72,566
Balance, End of Period	$1,209,131	$1,152,043

The

notes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	Three Months		Six Months
		March 31, 2006		Dec. 31, 2005
Periods ended June 30	2004	2003	2004	2003
(Thousands)
Net income	$38,066	$27,717	$158,618	$163,181
Liabilities
Other comprehensive income, net of tax
Current Liabilities
Net unrealized gains (losses) on investments, net of income tax (expense) for the three months of $- in 2004 and $(391) in 2003 and for the six months of $- in 2004 and $(642) in 2003	(947)	578	(927)	964
Current portion of long-term debt		$286,568		$326,527
Unrealized gains (losses) on derivatives qualified as hedges, net of income tax benefit (expense) for the three months of $(4,712) in 2004 and $4,737 in 2003 and for the six months of $(17,229) in 2004 and $(14,016) in 2003	7,104	(7,012)	25,811	21,808
Notes payable		19,000		121,347
Reclassification adjustment for derivative (gains) included in net income, net of income tax expense for the three months of $5,710 in 2004 and $2,544 in 2003 and for the six months of $11,010 in 2004 and $11,574 in 2003	(8,609)	(3,836)	(16,601)	(17,454)
Accounts payable and accrued liabilities		435,525		629,158
Net unrealized (losses) gains on derivatives qualified as hedges	(1,505)	(10,848)	9,210	4,354
Interest accrued		59,831		46,522
Total other comprehensive income (loss)	(2,452)	(10,270)	8,283	5,318
Taxes accrued		108,084		-
Comprehensive Income	$35,614	$17,447	$166,901	$168,499
Deferred income taxes		-		80,984
Derivative liabilities		41,129		2,019
Other		126,102		186,452
Total Current Liabilities		1,076,239		1,393,009
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation		784,361		797,544
Deferred income taxes		19,571		-
Gain on sale of generation assets		181,204		173,216
Pension benefits		21,137		22,798
Natural gas hedges		-		49,205
Other		104,047		124,251
Total regulatory liabilities		1,110,320		1,167,014
Other liabilities
Deferred income taxes		1,057,485		1,033,287
Nuclear plant obligations		227,872		234,907
Other postretirement benefits		430,231		428,691
Environmental remediation costs		168,374		166,462
Other		454,248		499,968
Total other liabilities		2,338,210		2,363,315
Total Regulatory and Other Liabilities		3,448,530		3,530,329
Debt owed to subsidiary holding solely parent debentures		355,670		355,670
Other long-term debt		3,350,609		3,311,395
Total long-term debt		3,706,279		3,667,065
Total Liabilities		8,231,048		8,590,403
Commitments and Contingencies		-		-
Preferred Stock of Subsidiaries Redeemable solely at the option of subsidiaries		24,631		24,631
Common Stock Equity Common stock		1,478		1,478
Capital in excess of par value		1,487,355		1,489,256
Retained earnings		1,385,147		1,294,580
Accumulated other comprehensive (loss) income		(472)		89,085
Treasury stock, at cost		(2,251)		(1,725)
Total Common Stock Equity		2,871,257		2,872,674
Total Liabilities and Stockholders' Equity		$11,126,936		$11,487,708

The

notes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Three months ended March 31,	2006	2005

(Thousands)
Operating Activities
Net income	$133,241	$154,366
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	98,908	89,615
Income taxes and investment tax credits deferred, net	(9,477)	(1,527)
Pension income	(7,466)	(6,393)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	(105,457)	(77,927)
Inventory	152,107	146,590
Prepayments and other current assets	5,730	(17,605)
Accounts payable and accrued liabilities	(167,313)	(26,583)
Interest accrued	13,309	16,098
Taxes accrued	71,002	80,852
Customer refund	(13,998)	(23,639)
Other current liabilities	(80,323)	(71,969)
Pension contributions	-	(54,000)
Other assets	56,519	77,027
Other liabilities	(50,988)	(33,632)

Net Cash Provided by Operating Activities	95,794	251,273

Investing Activities
Utility plant additions	(58,461)	(61,822)
Other property and investments additions	(1,207)	(34,859)
Other property and investments sold	691	13,867
Maturities of current investments available for sale	380,315	418,530
Purchases of current investments available for sale	(198,965)	(407,950)
Other	-	105

Net Cash Provided by (Used in) Investing Activities	122,373	(72,129)

Financing Activities
Issuance of common stock	-	991
Repurchase of common stock	(6,106)	(929)
Book overdraft	(7,166)	(2,847)
Long-term note issuances	40,000	-
Long-term note repayments	(40,894)	(28,358)
Notes payable three months or less, net	(95,489)	(85,490)
Notes payable issuances	38,275	7,000
Notes payable repayments	(45,133)	(3,000)
Dividends on common stock	(42,674)	(35,830)

Net Cash Used in Financing Activities	(159,187)	(148,463)

Net Increase in Cash and Cash Equivalents	58,980	30,681
Cash and Cash Equivalents, Beginning of Period	120,009	111,465

Cash and Cash Equivalents, End of Period	$178,989	$142,146

The

notes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Three months ended March 31,	2006	2005

(Thousands)
Balance, Beginning of Period	$1,294,580	$1,201,533
Add net income	133,241	154,366

	1,427,821	1,355,899
Deduct dividends on common stock	42,674	40,364

Balance, End of Period	$1,385,147	$1,315,535

The

notes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
Three months ended March 31,	2006	2005

(Thousands)
Net income	$133,241	$154,366
Other comprehensive income, net of tax
Net unrealized (losses) on investments, net of income tax benefit of $167 for 2006 and $ - for 2005	(252)	(23)
Net unrealized (losses) gains on derivatives qualified as hedges, net of income tax benefit (expense) of $76,497 for 2006 and $(28,868) for 2005	(120,202)	48,356
Reclassification adjustment for derivative losses included in net income, net of income tax (benefit) of $(20,416) for 2006 and $(21,371) for 2005	30,897	32,343

Net unrealized (losses) gains on derivatives qualified as hedges	(89,305)	80,699

Total other comprehensive (loss) income	(89,557)	80,676

Comprehensive Income	$43,684	$235,042

The

notes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

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

Energy East Corporation
Overview

Energy East ~~Corporation~~'s ~~(Energy~~primary ~~East~~operations, orour ~~the~~electric ~~company)~~and ~~management~~natural ~~focuses~~gas ~~its~~utility ~~strategic~~operations, ~~efforts~~are onsubject ~~those~~to ~~areas~~rate ofregulation ~~the~~established ~~company~~predominately ~~that~~by ~~have~~state ~~the~~utility ~~greatest~~commissions. ~~effect~~The approved regulatory treatment on ~~shareholder~~various ~~value.~~matters ~~Efficient~~significantly ~~operations~~affects ~~are~~our afinancial ~~key~~position, ~~aspect~~results of ~~increasing~~operations ~~shareholder~~and ~~value~~cash flows. AsWe ~~discussed~~have ~~below~~long-term rate plans for NYSEG, ~~management~~RG&E, ~~has~~CMP ~~implemented~~and ~~plans~~Berkshire toGas ~~achieve~~that currently provide for sharing of achieved savings ~~through~~among acustomers ~~company-wide~~and ~~restructuring,~~shareholders; ~~consolidation~~allow for recovery of ~~utility~~certain ~~support~~costs, ~~services~~including stranded costs; and ~~other~~provide ~~changes~~stable rates for customers and revenue predictability. 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.

InWe ~~addition,~~continue ~~because~~to ~~Energy~~focus ~~East's~~our ~~primary~~strategic ~~operations~~efforts -in ~~its~~the ~~electric~~areas ~~and~~that ~~natural~~have ~~gas utility operations - are subject to rate regulation,~~ the ~~approved~~greatest ~~regulatory~~effect ~~treatment~~ on ~~various~~customer ~~matters~~satisfaction ~~could~~and ~~significantly~~shareholder ~~affect~~value. ~~the~~NYSEG ~~company's~~implemented ~~operations~~a ~~and,~~new ~~therefore,~~customer ~~its~~care ~~financial~~system ~~position~~in ~~and~~the ~~results~~first quarter of ~~operations.~~2006 ~~In May 2004 Rochester Gas~~ and ~~Electric Corporation (~~RG&E), anexpects ~~operating~~to ~~company~~implement ~~of Energy East, received approval for long-term electric and natural gas rate plans. As~~ a ~~result,~~new ~~Energy~~customer ~~East~~care ~~now~~system ~~has~~in ~~long-term~~the ~~rate~~fourth ~~plans~~quarter ~~for all~~ of its major utility operating companies including New York State Electric & Gas Corporation (NYSEG), Central Maine Power Company (CMP), Connecticut Natural Gas Corporation (CNG), The Southern Connecticut Gas Company (SCG) and The Berkshire Gas Company (Berkshire Gas)2006. The plans provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including exogenous and uncontrollable costs, and provide stable rates for customers and revenue predictability for those six operating companies.

~~Over~~The ~~the~~continuing ~~last~~uncertainty ~~several~~in ~~years~~the ~~Energy~~evolution ~~East~~of ~~has~~the ~~focused~~utility ~~its strategic efforts on its electric and natural gas delivery operations~~industry, ~~rather~~particularly ~~than on~~ the ~~more~~electric ~~volatile~~utility ~~electricity generation business~~industry, ~~and~~ has ~~sought~~resulted toin ~~rationalize~~several ~~its~~federal ~~nonutility~~and ~~businesses~~state toregulatory ~~ensure~~proceedings ~~they~~that ~~fit~~could ~~its~~significantly ~~strategic~~affect ~~focus.~~our ~~As discussed below~~operations, ~~RG&E~~although ~~successfully~~their ~~completed~~outcomes ~~the~~are ~~sale~~difficult ~~of its Ginna nuclear generating station (Ginna)~~ to ~~Constellation Generation Group LLC (CGG) on June 10, 2004~~predict. InThose ~~addition~~proceedings, onsome ~~July~~of ~~26,~~which ~~2004,~~are ~~CMP~~discussed ~~Group~~below, ~~Inc.~~could ~~sold~~affect the ~~majority~~nature of the ~~assets~~electric ofand ~~its~~natural ~~subsidiary,~~gas ~~Union~~utility ~~Water~~industries ~~Power~~in ~~Company~~New ~~(UWP)~~York and New England.

The ~~continuing~~continued evolution of the ~~utility industry, particularly the~~ electric utility industry, ~~has~~is ~~resulted~~evidenced inby ~~several~~the ~~federal~~enactment ~~and~~of ~~state~~the ~~regulatory~~Energy ~~proceedings~~Policy ~~that~~Act ~~could~~of ~~significantly affect operations~~2005, ~~although~~which repealed the ~~outcomes~~Public ofUtility ~~those~~Holding ~~proceedings~~Company ~~are~~Act ~~difficult~~of to1935 ~~predict~~(PUHCA). ~~Those~~With ~~proceedings~~the ~~could~~repeal ~~have~~of anPUHCA, ~~effect~~the onFERC ~~the~~and ~~nature~~state ofutility ~~the~~commissions ~~electric~~have ~~and~~new ~~natural~~authority ~~gas~~to ~~utility~~regulate ~~industry~~and inmonitor, ~~New~~among ~~York~~other ~~and~~things, ~~New~~intercompany ~~England.~~cost ~~Recent~~allocations ~~events~~of inholding ~~the~~companies ~~proceedings~~such ~~are~~as ~~described~~Energy ~~below~~East.

~~The~~We ~~company~~engage ~~engages~~ in various investing and financing activities to meet ~~its~~our strategic objectives. ~~Investing~~Our ~~activities~~primary ~~are~~goal ~~conducted~~for ~~primarily~~investing activities is to maintain a reliable energy delivery infrastructure. ~~and~~We ~~are~~fund ~~funded~~our investing activities primarily with internally generated funds. ~~Financing~~We ~~activities,~~plan ~~therefore,~~to ~~are~~invest ~~focused~~nearly on$2 billion ~~maintaining~~in ~~adequate~~our ~~liquidity,~~energy ~~improving~~delivery ~~credit~~infrastructure ~~quality~~during ~~and~~the ~~minimizing~~next ~~the~~five ~~cost~~years, ofincluding ~~capital.~~approximately As$900 amillion ~~result~~dedicated ofto ~~the~~electric ~~Ginna~~reliability. ~~sale,~~We ~~the~~focus ~~company~~our ~~will~~financing ~~have~~activities ~~funds~~on ~~available~~maintaining toadequate ~~reduce~~liquidity ~~its~~and ~~outstanding~~credit ~~debt~~quality asand ~~well~~minimizing asour ~~that~~cost of ~~RG&E~~capital.

Our Management's ~~discussion~~Discussion and ~~analysis~~Analysis of Financial Condition and Results of Operations for the quarter ended March 31, 2006, should be read in conjunction with our Management's Discussion and Analysis of Financial Condition and Results of Operations, financial ~~condition~~statements and ~~results~~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 a 12-month period.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation
~~(a) Liquidity and Capital Resources~~Strategy

~~Restructuring~~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.

InOur ~~the~~long-term ~~first~~rate ~~quarter~~plans ofcontinue ~~2004~~to ~~the~~be ~~company~~a ~~completed~~critical ~~its~~component ~~consolidation~~ of ~~various~~our ~~accounting~~success. ~~and~~While ~~finance~~specific ~~functions.~~provisions ~~Energy~~may ~~East~~vary ~~recognized~~among aour $4public ~~million~~utility ~~total~~subsidiaries, ~~liability~~our ~~for~~overall anstrategy ~~enhanced~~includes ~~severance~~creating ~~program~~stable ~~for~~rate 83environments ~~accounting~~that ~~and~~allow ~~finance~~those ~~employees~~subsidiaries ~~who~~to ~~were~~earn ~~employed~~a ~~through~~fair ~~March~~return ~~31,~~while ~~2004.~~minimizing ~~The~~price ~~company~~increases ~~recorded~~and ~~approximately~~sharing $2achieved ~~million~~savings ofwith ~~that~~customers. ~~liability~~We asoffer of the ~~end~~most ofcomprehensive ~~the~~commodity ~~fourth~~programs ~~quarter~~in ofNew ~~2003~~York ~~and~~State, ~~recorded~~providing ~~the~~a ~~remaining~~full $2menu ~~million~~ of ~~the~~electricity ~~liability~~supply inchoices, ~~the~~including ~~first~~a ~~quarter~~fixed ofprice ~~2004.~~option ~~The~~for ~~liability~~customers ~~was~~who ~~entirely~~do ~~paid~~not ~~off~~want asto ofbe ~~June~~subject ~~30,~~to ~~2004.~~volatile wholesale electricity prices.

Electric Delivery Business Developments

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

~~RG&E~~NYSEG ~~2003~~ Electric ~~and Natural Gas~~ Rate ~~Agreements~~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 excess earnings. NYSEG also proposed, beginning on January 1, 2007, to reduce its nonbypassable wires charge by $163 million and increase delivery rates by $92 million, thereby maintaining an annualized overall electricity delivery rate decrease of approximately $71 million, or 9.5%. 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.

~~Key~~On ~~features~~January of9, 2006, NYSEG filed with the ~~Electric~~NYPSC ~~Rate~~revisions ~~Agreement~~and ~~include:~~updates to its September 2005 filing, while maintaining the overall framework of its proposed rate plan extension. In its January 2006 filing, NYSEG proposed to reduce its nonbypassable wires charge by an

~~Freezing~~Management's ~~electric~~Discussion ~~delivery~~and ~~rates~~Analysis ~~through~~of ~~December~~Financial ~~2008,~~Condition ~~except~~and ~~for~~Results ~~the implementation~~ of ~~a retail access surcharge effective May 1, 2004, that will recover $7 million annually.~~Operations

Allowing RG&E to recover its actual electricity supply costs beginning in May 2004.
Refunding to customers over the term of the plan $110 million of the approximately $357 million net proceeds from the sale of Ginna, including refunding $60 million after the closing, and refunding the remaining $50 million over the following three years. (See Sale of Ginna Station and Note 2 to the Condensed Financial Statements.)
Establishing an Asset Sale Gain Account (ASGA) with the net proceeds from the Ginna sale. Portions of the ASGA will be used as follows:
To cover $6 million of replacement purchased power costs incurred in connection with the 2003 Ginna refueling outage;
To provide the company with revenue equivalent to a $2 million annual increase in electric delivery rates;
To compensate RG&E for maximizing the sale value of Ginna through a credit to RG&E of $3.3 million annually over the term of the settlement;
RG&E estimates that at the end of 2008 approximately $121 million will remain in the ASGA, which may be used at the discretion of the NYPSC for rate moderation, among other things.
Establishing an earnings sharing mechanism to allow customers and stockholders to share equally in earnings above a 12.25% return on equity (ROE) target.
Creating and expanding initiatives to enable energy service companies (ESCOs) in RG&E's service territory to attract new customers. RG&E will be allowed to increase its earnings sharing threshold to 12.50% by meeting to-be-determined standards designed to measure improvements in its retail access program, such as increasing customer awareness of competitive alternatives and increasing customer migration.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation

~~Ensuring~~additional ~~that~~$5 ~~RG&E~~million, ~~continues~~for a revised reduction of $168 million, and proposed to ~~maintain~~increase ~~the~~its ~~high~~delivery ~~quality~~rates by an additional $12 million for a revised increase of ~~service~~$104 million. As a result of those revisions and ~~reliability~~updates, ~~that~~NYSEG itreduced ~~currently~~its ~~provides~~proposed byannualized ~~specifying~~overall ~~service~~electricity ~~quality~~delivery ~~and~~rate ~~reliability~~decrease ~~standards~~to ~~and~~$64 ~~capital~~million, ~~investment~~or ~~objectives~~8. 6%.

~~Key~~In ~~features~~a ruling issued on February 10, 2006, the ALJ in this proceeding denied a motion submitted by two ESCOs in January 2006 to dismiss the portion of the ~~Natural~~rate ~~Gas~~filing ~~Rate~~that ~~Agreement~~requests ~~include:~~NYPSC approval of NYSEG's Voice Your Choice program. The Consumer Protection Board, the Public Utility Law Project, and NYSEG opposed the ESCOs' motion. NYSEG stated in its filing that the motion was not supported by law, would deny NYSEG due process, including an evidentiary hearing, and distorted the evidence presented by NYSEG regarding its Voice Your Choice program. In the ruling, the ALJ concluded that the NYPSC's August 2004 Policy Statement was not intended as a binding order and, as a matter of law, does not preclude NYSEG from proposing to extend its Voice Your Choice program. The ALJ also determined that NYSEG's rate plan extension proceeding is the proper forum for consideration of issues presented in its proposal to extend its Voice Your Choice program.

~~Freezing~~In ~~natural~~early ~~gas~~February ~~delivery~~2006 ~~rates~~Staff ~~through~~of ~~December~~the ~~2008~~NYPSC (Staff) and six other parties submitted their direct cases. Staff presented only a one-year rate case. In its presentation, ~~except~~Staff ~~for~~proposed ~~the~~a ~~implementation~~delivery rate decrease of aapproximately ~~merchant~~$83 ~~function~~million, ~~charge~~or ~~that~~about ~~will~~13.4%, ~~recover~~which would equate to an overall delivery rate decrease of approximately $7226 million, ~~annually~~or ~~beginning~~about ~~May~~36.5%, 1including 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, ~~2004~~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 believes Staff's positions have no merit and is vigorously contesting these issues.

~~Implementing~~NYSEG afiled ~~weather~~its ~~normalization~~rebuttal ~~adjustment~~case on February 21, 2006, responding to ~~protect~~Staff's ~~both~~one-year ~~customers~~rate ~~and~~case ~~RG&E~~proposal ~~from~~by ~~fluctuating~~proposing ~~revenues~~to ~~due~~increase delivery rates by approximately $58 million, beginning on January 1, 2007. NYSEG also proposed to ~~swings~~amortize an equivalent portion of the ASGA liability through a customer bill credit in ~~temperature~~the ~~outside~~nonbypassable wires charge to offset the delivery increase, resulting in no delivery rate change for 2007. Although NYSEG's rebuttal testimony responds to Staff's one-year rate case proposal, NYSEG continues to support the adoption of a ~~normal~~six-year ~~range~~rate plan extension, including its NUG levelization proposal to moderate the delivery rate increase, and its proposal to extend its Voice Your Choice program.

~~Implementing~~Hearings ~~gas~~in ~~cost~~this ~~incentive~~proceeding ~~mechanisms~~concluded toon ~~provide~~April a21, ~~means~~2006, ofand ~~sharing~~various ~~with~~parties ~~customers~~filed ~~future~~briefs ~~gas~~on ~~supply~~April 26, ~~cost~~2006. ~~savings~~NYSEG ~~achieved~~cannot bypredict ~~RG&E~~the outcome of this proceeding.

~~Establishing~~Niagara ~~provisions~~Power ~~similar~~Project to those in the Electric Rate Agreement regarding earnings sharing and service quality and reliability. The level for earnings sharing is 12.00%, with the opportunity to increase to 12.25% if certain targets are achieved.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

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

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

contracts with the NYPA. (NYSEG and RG&E ~~Transmission~~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. On January 3, 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. On January 10, 2006, NYSEG and RG&E filed a response to NYPA's answer. NYSEG and RG&E are unable to predict the outcome of this proceeding.

CMP Alternative Rate Plan
: On December 7, 2005, CMP and the Office of the Public Advocate filed with the MPUC a stipulation for an extension of CMP's ARP 2000. This stipulation is also supported by low-income customer advocates and a coalition of industrial energy customers has signed the stipulation agreement. The stipulation maintains the provisions of CMP's ARP 2000 and proposes a three-year extension with four additional items. The stipulation provides for a 0.5% increase in the scheduled productivity offset of 2.75% for July 2006 and provides for productivity offsets averaging 2% for 2008, 2009 and 2010. The stipulation adds $2.2 million in assistance for low-income customers annually starting in 2006. Under the stipulation, CMP agrees to educate its customers on the regional benefits of adjusting usage during peak hours and demand periods and also agrees to limit the promotion of increased usage during specified higher demand periods. Finally, CMP agrees to commit to investing an additional $25 million through 2010 for enhancements to the reliability, safety and security of its distribution system.

~~NYPSC~~On ~~Collaborative~~February 1, 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 will respond to the recommendations in its brief to be filed on ~~End~~May ~~State~~19, 2006. The MPUC's decision is expected in the second quarter of ~~Energy~~2006. ~~Competition~~CMP cannot predict the outcome of this proceeding.

~~Regional~~Other ~~Transmission~~Proceedings ~~Organization~~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

Management's ~~discussion~~Discussion and ~~analysis~~Analysis of ~~financial~~Financial ~~condition~~Condition and ~~results~~Results of ~~operations~~Operations

Energy East Corporation

~~other~~complete ~~aspects~~information ofon the ~~FERC's RTO Order~~program. In ~~addition~~their filing, ~~ISO~~NYSEG ~~New~~and ~~England~~RG&E ~~and~~question whether the ~~New~~"PowerSwitch" ~~England~~program ~~transmission~~is ~~owners,~~consistent ~~including~~with ~~CMP,~~the ~~made~~NYPSC's aUniform ~~joint~~Business ~~compliance~~Practices. ~~filing~~NYSEG asand ~~required~~RG&E bybelieve the ~~RTO~~program ~~Order.~~results Atare ~~this~~suspect ~~time, CMP~~ and ~~the~~should ~~other~~not ~~New~~be ~~England~~used ~~transmission~~as ~~owners~~a ~~have~~basis ~~informed~~to expand the ~~FERC~~program ~~that~~to itother ~~needs~~utilities. toIn ~~resolve~~June 2005 the ~~issues~~NYPSC inapproved ~~the~~Central ~~request~~Hudson ~~for~~Gas ~~rehearing~~& Electric Corporation's retail access plan and ~~clarification~~rejected ~~before~~NYSEG's ~~the~~and ~~New~~RG&E's ~~England~~comments ~~transmission~~requesting ~~owners~~the ~~can~~NYPSC ~~make~~to anot ~~final~~take ~~decision~~action ~~regarding~~on ~~whether~~Central ~~and~~Hudson's ~~when~~plan and to ~~join~~suspend the ~~RTO~~development of new retail access initiatives that are based on flawed models.

~~CMP~~In ~~Collective~~a ~~Bargaining~~related ~~Agreement~~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 an order dated December 22, 2005, 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 also approved, with modifications, Central Hudson's proposed ESCO Referral Program. 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. The NYPSC permitted NYSEG to address the ESCO Referral Program within the context of its current rate case described above. Based on these latest developments, it is unclear whether or not NYSEG will be able to extend its Voice Your Choice program as a part of its ongoing electric rate proceeding.

~~CMP~~Locational ~~Stranded~~Installed ~~Cost~~Capacity ~~Proceeding~~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 LICAP market proposal based on an administratively set demand curve. In June 2005 the FERC ALJ issued an initial decision, essentially adopting the ISO-NE LICAP market proposal with minor modifications.

CMP ~~Nuclear~~and ~~Costs~~other parties that oppose the ISO-NE LICAP 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 LICAP 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 LICAP market proposal. In response to these protests, the FERC has delayed any possible implementation of LICAP until October 1, 2006, at the earliest and granted oral arguments to consider opposition to LICAP 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 on January 31, 2006, the settlement ALJ

Management's ~~discussion~~Discussion and ~~analysis~~Analysis of ~~financial~~Financial ~~condition~~Condition and ~~results~~Results of ~~operations~~Operations

Energy East Corporation

~~Pursuant~~reported to athe ~~year 2000 settlement (2000 Settlement) in a prior~~ FERC ~~rate~~that ~~case,~~most ~~Connecticut Yankee, on July 1, 2004, filed a revised schedule~~ of ~~decommissioning~~the ~~charges~~parties tohad bereached ~~collected~~an ~~from~~agreement ~~its~~in ~~wholesale~~principle ~~customers, based~~ on an ~~updated~~alternative ~~estimate~~to ~~of the costs of decommissioning~~LICAP. ~~Estimated~~The ~~decommissioning~~LICAP ~~and~~alternative ~~long-term~~will ~~spent~~provide ~~fuel~~fixed ~~storage~~transitional ~~costs~~capacity ~~for~~payments ~~the~~from ~~period~~2006 ~~2000~~until ~~through~~2010 ~~2023~~and ~~increased~~then byprovide ~~approximately~~capacity ~~$390~~payments ~~million~~based inon ~~2003~~a ~~dollars~~Forward ~~compared~~Capacity toMarket ~~the~~Auction ~~April 2000 estimate of $434 million approved by the FERC in the 2000 Settlement~~thereafter. ~~The~~CMP ~~revised~~opposed ~~estimate reflects~~ the ~~fact~~LICAP ~~that~~alternative ~~Connecticut~~at ~~Yankee~~a isNEPOOL ~~now~~participants ~~self-performing~~meeting. ~~all~~That ~~work~~alternative tohas ~~complete~~been ~~the~~filed ~~decommissioning~~with of the ~~plant~~FERC and ~~the~~various ~~termination~~parties ofhave ~~Bechtel~~submitted ~~Power~~comments ~~Corporation~~in ~~(Bechtel),~~support ~~the~~of ~~turnkey~~or ~~decommissioning contractor,~~ in ~~July~~opposition ~~2003.~~to ~~In addition,~~ the ~~revised estimate contains increases in the projected costs of spent fuel storage, security, and liability and property insurance~~alternative. The ~~estimated~~ISO-NE ~~remaining~~has ~~decommissioning~~requested ~~and~~that ~~long-term~~the ~~spent~~FERC ~~fuel~~rule ~~storage~~on ~~costs~~the asLICAP ofsettlement ~~December~~by ~~31,~~July ~~2003,~~2006 ~~are~~to ~~approximately~~allow ~~$504~~implementation ~~million~~ in ~~2003~~December ~~dollars~~2006.

~~Connecticut~~Presently, ~~Yankee~~CMP isand ~~seeking~~the ~~recovery~~MPUC, ofamong ~~incremental~~other ~~decommissioning~~parties, ~~costs~~are ~~and~~opposed ~~other~~to ~~damages~~the ~~from~~LICAP ~~Bechtel~~proposal and, ifthe ~~necessary~~alternative, because either proposal could have an adverse effect on Maine's economy by increasing its ~~surety.~~standard Inoffer ~~turn,~~rates ~~Bechtel~~an ~~has~~estimated ~~filed~~5% ato ~~complaint~~10%. Maine lawmakers held hearings in ~~Connecticut~~March ~~Superior~~to ~~Court~~study ~~seeking~~the ~~damages~~possibility of ~~$93~~Maine ~~million~~withdrawing ~~for~~from ~~wrongful~~ISO-NE ~~termination~~and ofwill ~~the~~conduct ~~decommissioning~~further ~~contract~~inquiry regarding regional energy markets and generation deregulation. ~~Connecticut~~CMP ~~Yankee~~cannot ~~has~~predict ~~filed~~the ~~counterclaims~~outcome ~~for~~of ~~excess~~these ~~completion~~settlement ~~costs~~discussions, ~~and~~how ~~other~~the ~~damages.~~FERC ~~Discovery~~will isrule ~~underway~~or ~~and~~what amodifications ~~trial~~the ~~has~~FERC ~~been~~might ~~scheduled~~make ~~for~~to ~~May~~the ~~2006~~filing.

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

OnOur ~~June~~natural ~~10,~~gas ~~2004,~~delivery ~~the~~business ~~Connecticut~~consists ~~Department~~ of ~~Public~~our ~~Utility~~regulated ~~Control~~natural ~~(DPUC)~~gas ~~and the Connecticut Office of Consumer Counsel filed a petition with the FERC asking the FERC to determine that~~transportation, ifstorage itand ~~should~~distribution ~~find~~operations ~~any~~in ofNew ~~Connecticut Yankee's decommissioning costs were not prudently incurred~~York, ~~the owners may not recover those costs in rates that are ultimately charged to retail customers but must be borne by the owners of~~ Connecticut ~~Yankee. Connecticut Yankee and its owners~~, ~~including~~Massachusetts ~~CMP, filed protests to contest this petition~~and Maine. ~~CMP cannot predict the outcome of these proceedings.~~

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: See Electric Delivery Business Developments.

~~Natural~~CNG ~~Gas~~Regulatory ~~Delivery Business~~ 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.

~~The~~On ~~company's~~March ~~natural~~21, ~~gas~~2006, ~~delivery~~the ~~business~~DPUC ~~consists~~notified ofCNG ~~its~~that ~~regulated~~it ~~natural~~had ~~gas~~initiated ~~transportation,~~a ~~storage~~general ~~and~~rate ~~distribution~~review ~~operations~~of inCNG ~~New~~pursuant ~~York,~~to Connecticut General Statutes, ~~Maine~~which ~~and Massachusetts~~state that the DPUC must conduct a financial review or require a rate case every four years. CNG expects to submit a general rate filing by the end of September 2006.

~~Natural~~Proposed ~~Gas~~New ~~Supply~~Accounting ~~Agreements~~Standard

~~Management's~~Pension ~~discussion~~Exposure ~~and analysis of financial condition and results of operations~~Draft

: On March 31, 2006, the FASB issued an Exposure Draft, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106 and 132(R). The Exposure Draft was issued as Phase I of a two-phase project to comprehensively reconsider existing guidance on accounting for pension and postretirement benefits. Phase II of the project is a multi-year phase that will address remaining issues and be conducted in collaboration with the International Accounting Standards Board. The Exposure Draft proposes to require an entity to: recognize a plan's over- or under-

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

~~NYSEG~~funded ~~Natural~~status ~~Gas~~on ~~Rate~~its ~~Plan~~balance sheet; recognize actuarial gains and losses 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 balance sheet.

OnComments ~~June~~on ~~30,~~the ~~2004,~~Exposure ~~NYSEG~~Draft ~~filed~~are adue ~~Joint~~at ~~Proposal~~the ~~executed~~end byof ~~NYSEG~~May 2006. One or more public roundtable meetings will be held in late June 2006 and ~~other~~a ~~parties,~~final ~~resolving~~Statement ~~outstanding~~is ~~issues~~expected to be issued in ~~NYSEG~~September 2006. For public companies the recognition of a plan's ~~Natural~~funded ~~Gas~~status ~~Rate~~and ~~Plan~~ related disclosure provisions are proposed to ~~its~~be ~~natural~~effective ~~gas~~for ~~delivery~~fiscal ~~rate~~years ~~design~~ending after December 15, ~~natural~~2006, ~~gas~~with ~~economic~~earlier ~~development~~application ~~plan~~encouraged and ~~its~~retrospective ~~natural~~application ~~gas~~(revision ~~Affordable~~of ~~Energy~~prior ~~Program~~periods) required. ~~Pursuant~~The provisions related to ~~NYSEG's~~measuring ~~Natural~~plan ~~Gas~~assets ~~Rate~~and ~~Plan,~~benefit ~~delivery~~obligations ~~rate~~as ~~designs~~of inthe date of the ~~Joint~~balance ~~Proposal~~sheet ~~were~~would ~~developed~~be applied for public companies for fiscal years beginning after December 15, 2006, and are not to be applied retrospectively, but earlier application would be encouraged. Energy East and RG&E each already measure plan assets and benefit obligations as of the ~~remaining~~balance ~~years~~sheet ondate. anAdoption ~~overall~~of ~~revenue~~a ~~neutral~~final ~~manner,~~standard consistent with the ~~billing~~Exposure ~~units~~Draft ~~and~~effective ~~firm~~for ~~delivery~~the ~~revenues~~fiscal ~~contained~~year inended ~~NYSEG~~December 31, 2006, could have a material effect on Energy East's ~~Natural~~and ~~Gas~~RG&E's ~~Rate~~financial ~~Plan.~~position ~~The~~by ~~company~~reducing ~~expects~~prepaid ~~the~~benefits ~~NYPSC~~and tocommon ~~address~~stock ~~the~~equity, ~~Joint~~but ~~Proposal~~is atnot ~~its~~expected ~~open~~to ~~session~~have a material effect on ~~September~~their ~~22,~~results ~~2004~~of operations or cash flows.

~~SCG~~(a) ~~Request~~Liquidity ~~for~~and ~~Recovery~~Capital ~~of Exogenous Costs~~Resources
~~CNG's~~Operating ~~Purchased Gas Adjustment Clause~~Activities
: Significant operating activities that affected cash flows during the first three months of 2006 included the following:

~~Connecticut~~A ~~Merger-Enabled~~reduction ~~Gas~~in ~~Supply~~accounts ~~Savings~~payable ~~and~~of ~~Gas~~$167 ~~Cost~~million ~~Reduction~~that ~~Plan~~reduced ~~Filings~~cash primarily resulting from payments for natural gas purchases,
~~Management's~~Increased ~~discussion~~receivables ~~and~~that ~~analysis~~reduced ofcash ~~financial~~by ~~condition~~$105 ~~and~~million, ~~results of operations~~and
~~Energy~~A ~~East~~reduction ~~Corporation~~in natural gas inventory that increased cash by $152 million.

~~$134,000~~While ~~for CNG and $9,000 for SCG. CNG and SCG filed comments and additional detail with regard to~~ the ~~draft~~foregoing ~~decision.~~are Onnormal ~~March~~activities ~~26,~~in ~~2004,~~ the ~~DPUC~~first ~~issued a notice that encouraged the parties to settle the MEGS issue~~quarter, ~~which~~their ~~resulted~~magnitudes inare ~~the~~larger ~~assignment~~than ofnormal ~~Prosecutorial~~due ~~Staff of the DPUC~~ to ~~assist~~higher inenergy ~~the settlement process~~prices. ~~The docket was suspended to allow the settlement process to proceed. CNG and SCG are diligently working toward settlement of the issues but cannot predict the final outcome of these proceedings.~~

Other Businesses
Sale of Other Businesses
Other Matters
Accounting Issues
FIN 46R
FASB Staff Position No. FAS 106-2
Investing and Financing Activities
Investing Activities
: Capital spending for the three months ended March 31, 2006, was $58 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.

Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
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.

~~During~~Management's ~~the~~Discussion ~~six~~and ~~months~~Analysis ~~ended June 30, 2004, the company issued 444,122 shares~~ of ~~common~~Financial ~~stock,~~Condition atand anResults ~~average price~~ of ~~$23.15 per share, through its Investor Services Program (formerly known as the Dividend Reinvestment and Stock Purchase Plan). The shares issued were original issue shares.~~Operations

In July 2004 the company replaced its $150 million 364-day revolving credit facility with a $150 million five-year revolving credit facility that expires in July 2009.
During the first quarter of 2004 the company awarded 242,038 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of $6 million based on the market price per share of common stock on the dates of the awards, which averaged $23.90.
NYSEG Financing Activities
In July 2004 NYSEG and RG&E replaced their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-year $230 million revolving credit facility with certain banks. NYSEG is permitted to borrow up to $180 million under the facility, RG&E is permitted to borrow up to $75 million, and NYSEG and RG&E are allowed to issue letters of credit totaling up to $40 million, not to exceed a combined total of $230 million.
In August 2004 NYSEG expects to refund $204 million of tax-exempt fixed-rate pollution control notes that have interest rates ranging from 5.70% to 6.05% with proceeds from the issuance of $204 million of multi-mode tax-exempt pollution control notes, which will initially be in a Dutch Auction mode. In July 2004 NYSEG entered into a forward starting swap to fix the interest rate on one of the tax-exempt pollution control notes in the Dutch Auction mode. NYSEG will pay a fixed rate of 3.80% and will receive 67% of the one-month LIBOR rate on a notional amount of $70 million.
RG&E Financing Activities
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation

OnWe ~~May~~repurchased 5250,000 ~~2004,~~shares ~~RG&E~~of ~~redeemed~~our ~~its~~common ~~remaining preferred~~ stock, ~~including:~~in ~~$12~~February ~~million of 4% Series F (120~~2006,~~000~~ ~~shares),~~primarily $8for ~~million~~grants of 4restricted stock.~~10%~~ ~~Series~~In HFebruary ~~(80,000~~2006 ~~shares),~~we $6awarded ~~million of 4 3/4% Series I (60~~248,~~000~~320 shares), ~~$5 million~~ of ~~4.10%~~our ~~Series~~common ~~J (50~~stock,~~000~~ ~~share),~~issued $6out ~~million~~ of ~~4.95%~~our ~~Series~~treasury ~~K (60~~stock,~~000~~ ~~shares)~~to ~~and~~certain ~~$10~~employees ~~million~~through ofour ~~4.55%~~Restricted ~~Series~~Stock ~~M (100~~Plan,~~000~~ ~~shares), all redeemed~~ at a ~~premium.~~weighted-average Ongrant ~~May~~date 6,fair ~~2004,~~value ~~RG&E redeemed, at a premium, $40 million~~ of ~~7.45% Series first mortgage bonds due July 2023, and the following Series of first mortgage bonds due March 2023:~~ $~~33 million of 7~~24.~~64%,~~83 $5per ~~million~~share of ~~7.66%,~~common ~~and~~stock ~~$12 million of 7~~awarded.~~67%.~~ ~~Those redemptions were financed through available cash and a short-term credit facility. The short-term credit facility was repaid with proceeds from the sale of Ginna.~~

InBeginning ~~July~~in ~~2004~~the ~~RG&E~~fourth ~~and~~quarter ~~NYSEG~~of ~~replaced~~2005 ~~their~~shares ~~joint~~needed ~~364-day~~for ~~revolving~~our ~~credit~~Investor ~~facility,~~Services ~~which~~Program ~~was~~are ~~due~~purchased ~~to expire~~ in ~~December~~the ~~2004,~~open ~~with a five-year $230 million revolving credit facility with certain banks~~market. ~~RG&E~~Cash isoutflows ~~permitted~~for ~~to borrow up to $75 million under~~ the ~~facility,~~first ~~NYSEG~~quarter isof ~~permitted~~2006 tofor ~~borrow~~dividends upon toour ~~$180~~common ~~million,~~stock ~~and~~equal ~~RG&E~~the ~~and~~amount ~~NYSEG~~of ~~are~~common ~~allowed~~stock todividends ~~issue~~payable ~~letters~~because ofshares ~~credit~~required ~~totaling~~for updividends toreinvested ~~$40~~in ~~million,~~our ~~not~~common tostock ~~exceed~~are anow ~~combined~~purchased ~~total~~in ofthe ~~$230~~open ~~million~~market.

In ~~August~~January ~~2004~~2006 ~~RG&E~~CMP ~~expects~~issued ~~to refund~~ $60 10 million of ~~fixed-rate~~Series ~~tax~~F medium-~~exempt~~term ~~mortgage~~notes ~~bonds~~at ~~that have rates ranging from 6~~5.3527%, todue ~~6.5%~~in ~~with~~2016, and ~~proceeds from the issuance of~~ $6030 million of ~~multi-mode~~Series ~~tax~~F medium-~~exempt~~term ~~pollution~~notes ~~control~~at ~~notes~~5.30%, ~~which~~due ~~will initially be~~ in a2016, ~~Dutch~~to ~~Auction~~refinance ~~mode~~maturing debt.

InEnergy East is planning to call in the ~~second~~third quarter of ~~2004~~2006, ~~RG&E~~at ~~declared~~par, ~~common~~its ~~dividends of~~ $~~170~~345 million, in8 ~~order~~1/4% Capital Securities (mandatorily redeemable trust preferred securities). We expect to ~~rebalance~~write ~~its~~off ~~capital~~approximately ~~structure~~$11 ~~after~~million of unamortized debt expense when the ~~Ginna~~8 ~~sale.~~1/4% ~~These~~Capital ~~funds~~Securities ~~will~~are becalled. ~~used~~In toNovember ~~reduce~~2006 ~~debt~~Energy ~~outstanding~~East's at$232 million 5.75% note matures. Energy East has entered into several arrangements to hedge interest rates in connection with the refinancing of these securities.

~~Other~~In ~~Financing~~April ~~Activities~~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%.

InManagement's ~~the~~Discussion ~~second~~and ~~quarter~~Analysis of ~~2004~~Financial ~~Berkshire~~Condition ~~Gas, CNG~~ and ~~SCG~~Results renewed their joint $105 million 364-day revolving credit facility. The amounts the companies are permitted to borrow up to: Berkshire Gas - $15 million, CNG - $50 million and SCG - $55 million, not to exceed a combined total of ~~$105 million.~~Operations

Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
(b) Results of Operations

Three months ended June 30	2004	2003	Change
Three months ended March 31,	2006	2005
(Thousands, except per share amounts)
Operating Revenues	$~~980~~1,~~566~~696,554	$~~979~~1,~~113~~637,278	-
Operating Income	$~~233~~294,~~806~~441	$~~124~~320,~~351~~817	~~88%~~
Income from Continuing Operations	$42,782	$28,333	49%
Net Income	$133,241	$154,366
Net Income	$38,066	$27,717	37%
Average Common Shares Outstanding, basic	147,034	146,875
Average Common Shares Outstanding, basic	146,148	145,415	1%
Earnings per Share, basic	$.91	$1.05
Earnings Per Share from Continuing Operations, basic and diluted	$.29	$.19	53%
Earnings per Share, diluted	$.90	$1.05
Earnings Per Share, basic and diluted	$.26	$.19	37%
Dividends Paid per Share	$.29	$.275
Dividends Paid Per Share	$.26	$.25	4%

Earnings ~~from continuing operations were 29 cents~~ per share for the quarter ended June 30, 2004, compared to 19 cents per share for the quarter ended June 30, 2003. The increase is primarily due to one-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements, which increased earnings 7 cents per share. The one-time effects include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory determination. Ongoing effects from RG&E's Electric and Natural Gas Rate Agreements added 5 cents per share to earnings, and include increases as a result of RG&E's electric retail access surcharge and natural gas merchant function charge, and annual credits to RG&E from the ASGA as provided in the Electric Rate Agreement. (See Share

Six months ended June 30	2004	2003	Change
(Thousands, except per share amounts)
Operating Revenues	$2,561,639	$2,483,944	3%
Operating Income	$501,151	$418,294	20%
Income from Continuing Operations	$163,491	$160,024	2%
Net Income	$158,618	$163,181	(3%)
Average Common Shares Outstanding, basic	146,116	145,256	1%
Earnings Per Share from Continuing Operations, basic	$1.12	$1.10	2%
Earnings Per Share from Continuing Operations, diluted	$1.11	$1.10	1%
Earnings Per Share, basic	$1.09	$1.12	(3%)
Earnings Per Share, diluted	$1.08	$1.12	(4%)
Dividends Paid Per Share	$.52	$.50	4%

Earnings per share, basic for the quarter ended March 31, 2006, decreased 14 cents compared to the quarter ended March 31, 2005, primarily because of:

~~Earnings~~A ~~from~~decrease ~~continuing~~of ~~operations~~6 ~~were~~cents ~~$1.12 per share~~ for ~~the~~higher ~~six~~operating ~~months~~and ~~ended~~maintenance ~~June~~expense ~~30,~~including ~~2004,~~4 ~~compared~~cents ~~to $1.10 per share~~ for ~~the~~storm ~~six months ended June 30~~restoration, 2003. The increase is primarily the result of the second quarter effects of the sale of Ginna and RG&E's Electric and Natural Gas Rate Agreements discussed above, and because of integration savings and other cost reductions. Earnings were reduced 5 cents per share due to the accumulated effects of stock-based compensation expenses as a result of the changes in the market value of Energy East stock during the first two quarters of 2004 as compared to the same periods last year. Earnings were reduced another 9 cents per share because of lower natural gas deliveries due to milder weather.
~~Management's~~A ~~discussion~~decrease ~~and~~of ~~analysis~~4 ofcents ~~financial~~for ~~condition~~higher interest expense resulting from higher rates on short-term and ~~results~~variable ofrate ~~operations~~debt and higher carrying costs on regulatory liabilities, and
~~Energy~~A ~~East~~decrease ~~Corporation~~of 3 cents resulting from lower electricity sales due to mild winter weather.

Natural gas margins were essentially unchanged from 2005 as the effect of lower delivery volumes was largely offset by weather normalization accruals.

Operating Results for the Electric Delivery Business

Three months ended June 30	2004	2003	Change
Three months ended March 31,	2006	2005
(Thousands)
Retail Deliveries - Megawatt-hours	7,295	7,141	2%
Retail Deliveries (MWh)	7,764	8,076
Operating Revenues	$641,057	$640,035	-
Retail Commodity Sales (MWh) (1)	1,224	1,326
Operating Expenses	$425,098	$536,329	(21%)
Wholesale Sales (MWh)	2,503	1,984
Operating Income	$215,959	$103,706	108%
Operating Revenues	$785,306	$768,322
Operating Expenses	$632,355	$584,436
Operating Income	$152,951	$183,886

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

Operating ~~expenses decreased $111 million primarily due to RG&E's recognition of a $319 million pretax gain on the Ginna sale, partially offset by RG&E's deferral of the gain net of tax of $214 million.~~ Revenues
: The $17 million increase in operating revenues for the first quarter of 2006 was primarily the result of:

Six months ended June 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	15,345	15,231	1%
Operating Revenues	$1,371,652	$1,398,748	(2%)
Operating Expenses	$1,012,909	$1,139,237	(11%)
Operating Income	$358,743	$259,511	38%

An increase of $41 million in wholesale sales resulting from higher volumes for NYSEG and RG&E,
~~Operating~~An ~~revenues~~increase ~~for the six months decreased $27 million. The primary factors were revenue decreases~~ of ~~approximately~~ $2112 million ~~because~~due ofto ~~rate~~higher ~~reductions~~prices for ~~CMP~~retail toelectric ~~reflect~~energy ~~lower~~supplied ~~amortization~~by ofNYSEG ~~storm~~ and ~~demand-side management costs; and $22 million due to a change in market structure for~~ RG&E ~~that~~under ~~allows~~various ~~ESCOs~~commodity tooptions ~~provide~~where ~~electricity,~~they ~~resulting~~provide ~~in lower retail revenues offset by higher wholesale revenues and lower fuel costs. Those decreases were partially offset by increased retail deliveries of $4 million~~supply, ~~increased wholesale revenues of $8 million~~ and ~~an $8 million increase in transmission revenues for NYSEG.~~
~~Operating~~An ~~expenses~~increase ~~for~~of ~~the six months decreased~~ $~~126~~28 million ~~primarily~~in ~~due~~other torevenues ~~RG&E's~~including ~~recognition of a~~ $~~319~~19 million ~~pretax~~in ~~gain~~lower onaccruals ~~the~~for ~~Ginna~~earnings ~~sale,~~sharing. ~~partially~~This ~~offset~~$19 bymillion ~~RG&E's~~increase ~~deferral~~included ~~of the gain net of tax of~~ $~~214~~14 million. ~~In addition, operating expenses~~ for the ~~first~~finalization ~~quarter~~ of ~~2004~~the ~~decreased~~actual ~~$15~~amount ~~million~~for ~~primarily~~2005 ~~due~~per tothe aannual ~~reduction~~compliance infilings ~~purchased~~by ~~power~~NYSEG ~~costs.~~and RG&E.

Management's ~~discussion~~Discussion and ~~analysis~~Analysis of ~~financial~~Financial ~~condition~~Condition and ~~results~~Results of ~~operations~~Operations

Energy East Corporation

Those increases were partially offset by:

A decrease of $23 million resulting from reduced electricity sales under the companies' commodity programs due largely to warmer winter weather,
A decrease of $10 million resulting from lower retail deliveries due largely to warmer winter weather, and
A decrease of $31 million resulting from lower transition charges. The transition charge reflects the difference between the market price of electricity and the prices set by our long-term electricity supply contracts. This charge decreases as market prices increase. Changes in the transition charge have no effect on earnings.

Operating Expenses
: The $48 million increase in operating expenses for the first quarter of 2006 was primarily the result of:

An increase of $22 million in purchased power costs resulting from $36 million for higher wholesale market prices for electricity, reduced by $14 million due to the expiration of a major NUG contract,
An increase of $20 million in operating and maintenance costs including $10 million for storm restoration, $4 million for uncollectible expense, $2 million for stock option expense and $4 million for a variety of other items, and
An increase of $5 million in other taxes.

Operating Results for the Natural Gas Delivery Business

Three months ended June 30	2004	2003	Change
Three months ended March 31,	2006	2005
(Thousands
(Thousands)
Retail Deliveries - Dekatherms	35,952	39,026	(8%)
Retail Deliveries (Dth)	75,645	86,257
Operating Revenues	$240,282	$264,054	(9%)
Wholesale Sales (Dth)	47	350
Operating Expenses	$232,485	$244,033	(5%)
Operating Revenues	$756,899	$721,197
Operating Income	$7,797	$20,021	(61%)
Operating Expenses	$619,961	$587,065
Operating Income	$136,938	$134,132

Operating revenues decreased $24 million for the second quarter of 2004 primarily due to lower deliveries that reduced revenues $40 million, partially offset by higher gas costs that are passed on to customers that increased revenues $16 million. Revenues
: The $36 million increase in operating revenues for the first quarter of 2006 was primarily the result of:

~~Operating~~An ~~expenses~~increase ~~decreased~~of $12110 million ~~compared~~primarily toas ~~the prior year quarter. The primary cause was~~ a ~~decrease~~result ~~in volume~~ of ~~natural~~higher ~~gas~~market ~~purchases~~prices of ~~$14 million. This decrease was offset by higher~~ natural gas ~~prices~~that ofwere ~~$10~~passed ~~million.~~on ~~Lower~~to ~~wholesale~~customers, ~~volumes decreased expenses $4 million for the quarter.~~

Six months ended June 30	2004	2003	Change
(Thousands
Retail Deliveries - Dekatherms	123,549	128,242	(4%)
Operating Revenues	$922,006	$904,167	2%
Operating Expenses	$789,191	$751,569	5%
Operating Income	$132,815	$152,598	(13%)

An increase of $9 million as a result of higher base rates approved for SCG effective January 1, 2006,
~~Operating~~An ~~revenues increased $18 million for the six months compared to the prior year period. The~~ increase isof ~~primarily due to an~~ $808 million ~~increase in revenues~~ due to higher ~~natural~~billings ~~gas~~resulting ~~costs,~~from ~~which~~weather ~~are~~normalization ~~passed on to customers~~adjustments, ~~partially offset by lower deliveries of $40 million. Other items, including lower transportation revenues~~ and ~~wholesale entitlements further decreased revenues.~~
~~Operating~~An ~~expenses~~increase ~~increased $42 million for the six months ended June 30, 2004, primarily due to higher natural gas prices~~ of $626 million, ~~partially~~in ~~offset~~other ~~by fewer purchases of natural gas of $28 million as a result of lower deliveries~~revenues.

Central Maine Power Company Condensed Consolidated Statements of Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30	2004	2003	2004	2003
(Thousands)
Operating Revenues
Sales and services	$129,748	$135,259	$292,498	$311,676
Operating Expenses
Electricity purchased	57,422	60,048	120,395	120,686
Other operating expenses	37,825	41,817	79,484	88,305
Maintenance	7,016	8,765	14,841	16,135
Depreciation and amortization	13,173	10,145	21,297	20,365
Other taxes	3,317	3,448	8,324	10,404
Total Operating Expenses	118,753	124,223	244,341	255,895
Operating Income	10,995	11,036	48,157	55,781
Other (Income)	(1,032)	(761)	(2,083)	(1,748)
Other Deductions	164	420	299	799
Interest Charges, Net	6,131	6,614	12,272	13,287
Income Before Income Taxes	5,732	4,763	37,669	43,443
Income Taxes	2,302	1,942	13,412	16,520
Net Income	3,430	2,821	24,257	26,923
Preferred Stock Dividends	361	361	721	721
Earnings Available for Common Stock	$3,069	$2,460	$23,536	$26,202

Those increases were partially offset by a decrease of $97 million as a result of lower delivery volumes due largely to warmer winter weather.

Central Maine Power Company Condensed Consolidated Balance Sheets - (Unaudited)
June 30, 2004 Dec. 31, 2003
(Thousands)
Assets
Current Assets
Cash and cash equivalents $14,970 $11,627
Accounts receivable, net 100,153 113,992
Materials and supplies, at average cost 6,734 6,571
Accumulated deferred income tax benefits, net 1,232 1,232
Prepayments and other current assets 4,153 7,135
Total Current Assets 127,242 140,557
Utility Plant, at Original Cost
Electric 1,358,980 1,337,931
Less accumulated depreciation 466,103 451,407
Net Utility Plant in Service 892,877 886,524
Construction work in progress 14,818 15,953
Total Utility Plant 907,695 902,477
Other Property and Investments, Net 23,975 25,475
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations 160,322 173,548
Unfunded future income taxes 104,276 104,276
Unamortized loss on debt reacquisitions 8,059 8,646
Demand-side management program costs 4,589 5,281
Environmental remediation costs 1,613 2,614
Nonutility generator termination agreement 5,319 5,944
Other 74,390 65,145
Total regulatory assets 358,568 365,454
Other assets
Goodwill, net 324,938 324,938
Prepaid pension benefits 35,897 29,623
Other 10,189 18,329
Total other assets 371,024 372,890
Total Regulatory and Other Assets 729,592 738,344
Total Assets $1,788,504 $1,806,853
Operating Expenses
: The $33 million increase in operating expenses for the first quarter of 2006 was primarily the result of:

Central Maine Power Company Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$3,007	$2,999
Notes payable	25,000	15,000
Accounts payable and accrued liabilities	53,211	45,815
Interest accrued	5,471	5,397
Taxes accrued	2,626	1,206
Other	24,192	48,322
Total Current Liabilities	113,507	118,739
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	84,096	80,128
Deferred income taxes	78,748	77,849
Gain on sale of generation assets	58,674	76,998
Other	21,708	17,127
Total regulatory liabilities	243,226	252,102
Other liabilities
Deferred income taxes	75,272	65,555
Nuclear plant obligations	160,322	173,548
Other postretirement benefits	75,258	73,181
Environmental remediation costs	2,867	3,017
Other	114,062	113,880
Total other liabilities	427,781	429,181
Total Regulatory and Other Liabilities	671,007	681,283
Long-term debt	313,046	314,511
Total Liabilities	1,097,560	1,114,533
Commitments	-	-
Preferred Stock Preferred stock	35,571	35,571
Common Stock Equity Common stock	156,057	156,057
Capital in excess of par value	482,882	482,794
Retained earnings	33,608	35,072
Accumulated other comprehensive (loss)	(17,174)	(17,174)
Total Common Stock Equity	655,373	656,749
Total Liabilities and Stockholder's Equity	$1,788,504	$1,806,853

An increase of $105 million due to higher market prices for purchased natural gas.

Central Maine Power Company Condensed Consolidated Statements of Cash Flows - (Unaudited)
Six months ended June 30	2004	2003
(Thousands)
Net Cash Provided by Operating Activities	$42,853	$49,218
Investing Activities
Utility plant additions	(24,506)	(12,847)
Other	2,220	119
Net Cash Used in Investing Activities	(22,286)	(12,728)
Financing Activities
Long-term note repayments	(1,503)	(1,486)
Notes payable three months or less, net	10,000	-
Dividends on common and preferred stock	(25,721)	(25,721)
Net Cash Used in Financing Activities	(17,224)	(27,207)
Net (Decrease) Increase in Cash and Cash Equivalents	3,343	9,283
Cash and Cash Equivalents, Beginning of Period	11,627	20,415
Cash and Cash Equivalents, End of Period	$14,970	$29,698

That increase was partially offset by:

Central Maine Power Company Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Six months ended June 30	2004	2003
(Thousands)
Balance, Beginning of Period	$35,072	$31,682
Add net income	24,257	26,923
	59,329	58,605
Deduct Dividends on Capital Stock
Preferred	721	721
Common	25,000	25,000
	25,721	25,721
Balance, End of Period	$33,608	$32,884

A reduction of $72 million due to lower volumes of natural gas purchases.

Central Maine Power Company Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
Three Months Six Months
Periods ended June 30 2004 2003 2004 2003
(Thousands)
Net income $3,430 $2,821 $24,257 $26,923
Other comprehensive income, net of tax
Net unrealized (losses) on derivatives qualified as hedges, net of income tax benefit of $- for the three months in 2004 and $624 in 2003, and $- for the six months in 2004 and $631 in 2003 - (904) - (915)
Total other comprehensive income - (904) - (915)
Comprehensive Income $3,430 $1,917 $24,257 $26,008
Central Maine Power Company
(a) Liquidity and Capital Resources
Restructuring
See Energy East's Item 2(a), Restructuring, for this discussion.
Electric Delivery Business
CMP's electric delivery business consists of its regulated electricity transmission and distribution operations.
CMP Alternative Rate Plan: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.
Regional Transmission Organization: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.
CMP Collective Bargaining Agreement: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.
Other Matters
Accounting Issues
FIN 46R
FASB Staff Position No. FAS 106-2
Investing Activities
Capital spending for the first six months of 2004 was $25 million. Capital spending is projected to be $50
Management's discussion and analysis of financial condition and results of operations
Central Maine Power Company
(b) Results of Operations
Three months ended June 30 2004 2003 Change
(Thousands)
Retail Deliveries - Megawatt-hours 2,124 2,110 1%
Operating Revenues $129,748 $135,259 (4%)
Operating Expenses $118,753 $124,223 (4%)
Operating Income $10,995 $11,036 -
Earnings Available for Common Stock $3,069 $2,460 25%
Earnings for the quarter increased less than $1 million. A slight decrease in operating income was offset by higher other income and lower interest expense.
Operating revenues for the quarter decreased by $6 million due primarily to rate reductions totaling $5 million reflecting lower amortization of storm and demand-side management costs.
Operating expenses decreased $5 million for the quarter primarily due to lower amortization of ice storm and other costs of $4 million and lower NUG costs of $2 million.
Six months ended June 30 2004 2003 Change
(Thousands)
Retail Deliveries - Megawatt-hours 4,459 4,373 2%
Operating Revenues $292,498 $311,676 (6%)
Operating Expenses $244,341 $255,895 (5%)
Operating Income $48,157 $55,781 (14%)
Earnings Available for Common Stock $23,536 $26,202 (10%)
Earnings for the six months decreased $3 million compared to the prior year period primarily as a result of lower operating revenues.
Operating revenues for the six months decreased $19 million due primarily to a $23 million decrease because of rate reductions reflecting mainly lower amortization of storm and demand-side management costs. That decrease was partially offset by an increase of $4 million for higher deliveries resulting from economic growth.
Operating expenses for the six months decreased $12 million primarily due to lower amortization of ice storm and other costs of $8 million and a decrease in other taxes of $2 million.
Item 1.
Financial Statements

New York State Electric & Gas Corporation Condensed Statements of Income - (Unaudited)
Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	Three Months		Six Months
	March 31, 2006	Dec. 31, 2005
Periods ended June 30	2004	2003	2004	2003
(Thousands)
(Thousands)
Assets
Operating Revenues
Current Assets
Electric	$358,521	$338,353	$762,505	$744,320
Cash and cash equivalents	$37,705	$28,752
Natural Gas	69,974	75,011	258,204	244,775
Investments available for sale	-	53,325
Total Operating Revenues	428,495	413,364	1,020,709	989,095
Accounts receivable and unbilled revenues, net	212,242	193,807
Operating Expenses
Fuel and natural gas in storage, at average cost	15,951	57,434
Electricity purchased	193,753	179,603	422,430	398,114
Materials and supplies, at average cost	14,223	13,204
Natural gas purchased	41,452	43,569	173,747	150,626
Deferred income taxes	8,869	-
Other operating expenses	51,642	52,685	110,984	100,499
Derivative assets	53	21,597
Maintenance	19,195	17,034	34,095	38,430
Prepayments and other current assets	50,404	27,047
Depreciation and amortization	25,849	25,063	51,214	49,995
Total Current Assets	339,447	395,166
Other taxes	25,669	25,291	56,081	60,664
Utility Plant, at Original Cost
Total Operating Expenses	357,560	343,245	848,551	798,328
Electric	1,264,234	1,258,330
Operating Income	70,935	70,119	172,158	190,767
Natural gas	575,252	572,943
Other (Income)	(216)	(184)	(172)	(2,108)
Common	197,601	199,015
Other Deductions	454	(1,553)	172	(1,297)
	2,037,087	2,030,288
Interest Charges, Net	18,597	21,022	37,398	40,360
Less accumulated depreciation	599,278	583,557
Income Before Income Taxes	52,100	50,834	134,760	153,812
Net Utility Plant in Service	1,437,809	1,446,731
Income Taxes	21,204	20,911	50,947	63,272
Construction work in progress	24,215	18,748
Net Income	30,896	29,923	83,813	90,540
Total Utility Plant	1,462,024	1,465,479
Preferred Stock Dividends	99	99	198	198
Other Property and Investments	11,755	11,634
Earnings Available for Common Stock	$30,797	$29,824	$83,615	$90,342
Regulatory and Other Assets
Regulatory assets
Deferred income taxes	-	12,007
Nuclear plant obligations	176,087	183,039
Environmental remediation costs	24,965	25,013
Unamortized loss on debt reacquisitions	13,494	14,336
Nonutility generator termination agreement	79,938	82,243
Other	128,229	127,867
Total regulatory assets	422,713	444,505
Other assets
Prepaid pension benefits	51,881	48,368
Other	18,381	17,121
Total other assets	70,262	65,489
Total Regulatory and Other Assets	492,975	509,994
Total Assets	$2,306,201	$2,382,273

New York State Electric & Gas Corporation Condensed Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$17,460	$14,458
Special deposits	5,094	30,353
Accounts receivable, net	237,317	290,166
Fuel, at average cost	26,815	43,207
Materials and supplies, at average cost	6,052	5,893
Accumulated deferred income tax benefits, net	5,415	5,500
Prepayments	21,981	28,917
Total Current Assets	320,134	418,494
Utility Plant, at Original Cost
Electric	2,652,953	2,593,090
Natural gas	698,092	688,705
Common	139,745	120,584
	3,490,790	3,402,379
Less accumulated depreciation	1,183,927	1,144,385
Net Utility Plant in Service	2,306,863	2,257,994
Construction work in progress	12,749	55,638
Total Utility Plant	2,319,612	2,313,632
Other Property and Investments, Net	37,886	37,872
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes	44,261	42,366
Unamortized loss on debt reacquisitions	36,996	38,863
Environmental remediation costs	74,409	74,734
Deferred income taxes	63,794	71,095
Other	41,827	53,238
Total regulatory assets	261,287	280,296
Other assets
Goodwill, net	11,199	11,199
Prepaid pension benefits	474,770	450,817
Other	99,097	75,255
Total other assets	585,066	537,271
Total Regulatory and Other Assets	846,353	817,567
Total Assets	$3,523,985	$3,587,565

The

notes on pages 24 through 29 are an integral part of the condensed financial statements.

New York State Electric & Gas Corporation Condensed Balance Sheets - (Unaudited)
Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003
	March 31, 2006	Dec. 31, 2005
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$338	$710
Accounts payable and accrued liabilities	$82,392	$123,145
Notes payable	6,197	41,400
Interest accrued	7,894	9,830
Accounts payable and accrued liabilities	143,611	148,918
Taxes accrued	30,623	16,438
Interest accrued	8,748	10,068
Deferred income taxes	-	698
Taxes accrued	13,350	15,367
Other	39,565	37,958
Other	27,904	74,819
Total Current Liabilities	160,474	188,069
Total Current Liabilities	200,148	291,282
Regulatory and Other Liabilities
Regulatory liabilities
Gain on sale of generation assets	52,809	52,642
Accrued removal obligation	182,553	182,346
Accrued removal obligation	314,463	304,065
Deferred income taxes	16,349	-
Other	21,363	21,571
Unfunded future income taxes	34,612	89,104
Total regulatory liabilities	388,635	378,278
Gain on sale of generation assets	127,570	111,262
Natural gas hedges	-	21,969
Other	50,069	51,015
Total regulatory liabilities	411,153	455,696
Other liabilities
Deferred income taxes	~~532~~168,~~176~~463	~~522~~167,~~919~~785
Other postretirement benefits	214,795	208,393
Nuclear waste disposal	109,702	108,570
Asset retirement obligation	382	377
Other postretirement benefits	80,312	80,045
Environmental remediation costs	9736,~~075~~554	9736,~~400~~506
Other	5951,~~386~~792	5065,~~840~~146
Total other liabilities	~~903~~446,~~814~~823	~~879~~458,~~929~~052
Total Regulatory and Other Liabilities	1857,~~292,449~~976	1913,~~258,207~~748
Long-term debt	1697,~~065,829~~969	1697,~~065,590~~951
Total Liabilities	21,~~558~~716,~~426~~419	21,~~615~~799,~~079~~768
Commitments	-	-
Commitments and Contingencies	-	-
Preferred Stock Redeemable solely at NYSEG's option	10,159	10,159
Common Stock Equity
Common Stock Equity Common stock	430,057	430,057
Common stock	194,429	194,429
Capital in excess of par value	~~277~~483,~~543~~418	~~277~~483,~~462~~252
Retained earnings	~~212~~33,~~663~~834	~~229~~28,~~048~~549
Accumulated other comprehensive income	35,137	25,760
Accumulated other comprehensive (loss)	(4,661)	(6,487)
Total Common Stock Equity	955,400	962,327
Treasury stock, at cost	(117,238)	(117,238)
Total Liabilities and Stockholder's Equity	$3,523,985	$3,587,565
Total Common Stock Equity	589,782	582,505
Total Liabilities and Stockholder's Equity	$2,306,201	$2,382,273

New York State Electric & Gas Corporation Condensed Statements of Cash Flows - (Unaudited)
Six months ended June 30	2004	2003
(Thousands)
Net Cash Provided by Operating Activities	$164,178	$107,090
Investing Activities
Utility plant additions	(50,662)	(38,836)
Proceeds from sale of utility plant	-	211
Special deposits	25,259	(81,128)
Other	1	(17)
Net Cash Used in Investing Activities	(25,402)	(119,770)
Financing Activities
Notes payable three months or less, net	(35,203)	5,000
Repayments of first mortgage bonds, including net premiums	-	(74,390)
Long-term note issuances	(373)	196,986
Dividends on common and preferred stock	(100,198)	(90,198)
Net Cash Used in Financing Activities	(135,774)	37,398
Net Increase (Decrease) in Cash and Cash Equivalents	3,002	24,718
Cash and Cash Equivalents, Beginning of Period	14,458	11,490
Cash and Cash Equivalents, End of Period	$17,460	$36,208

The

notes on pages 24 through 29 are an integral part of the condensed financial statements.

New York State Electric & Gas Corporation Condensed Statements of Retained Earnings - (Unaudited)
Rochester Gas and Electric Corporation Condensed Statements of Income - (Unaudited)
Six months ended June 30	2004	2003
Three months ended March 31,	2006	2005
(Thousands)
Balance, Beginning of Period	$229,048	$206,519
Operating Revenues
Add net income	83,813	90,540
Electric	$185,638	$160,156
	312,861	297,059
Natural gas	160,873	155,564
Deduct Dividends on Capital Stock
Total Operating Revenues	346,511	315,720
Preferred	198	198
Operating Expenses
Common	100,000	90,000
Electricity purchased and fuel used in generation	75,905	64,039
	100,198	90,198
Natural gas purchased	108,833	104,148
Balance, End of Period	$212,663	$206,861
Other operating expenses	38,765	39,309
Maintenance	10,908	10,398
Depreciation and amortization	17,818	17,771
Other taxes	17,114	15,177
Total Operating Expenses	269,343	250,842
Operating Income	77,168	64,878
Other (Income)	(1,064)	(1,554)
Other Deductions	182	128
Interest Charges, Net	14,283	13,982
Income Before Income Taxes	63,767	52,322
Income Taxes	23,482	21,394
Net Income	$40,285	$30,928

New York State Electric & Gas Corporation Condensed Statements of Comprehensive Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30	2004	2003	2004	2003
(Thousands)
Net income	$30,896	$29,923	$83,813	$90,540
Other comprehensive income, net of tax
Net unrealized gains on investments, net of income tax benefit for the three months of $- in 2004 and $(173) in 2003 and for the six months of $- in 2004 and $(166) in 2003	-	260	-	250
Unrealized (losses) gains on derivatives qualified as hedges, net of income tax benefit (expense) for the three months of $(4,712) in 2004 and $2,565 in 2003 and for the six months of $(17,229) in 2004 and $(16,184) in 2003	7,105	(3,868)	25,979	24,402
Reclassification adjustment for derivative (gains) included in net income, net of income tax expense for the three months of $5,710 in 2004 and $2,563 in 2003 and for the six months of $11,010 in 2004 and $11,590 in 2003	(8,609)	(3,864)	(16,601)	(17,476)
Net unrealized (losses) gains on derivatives qualified as hedges	(1,504)	(7,732)	9,378	6,926
Total other comprehensive income	(1,504)	(7,472)	9,378	7,176
Comprehensive Income	$29,392	$22,451	$93,191	$97,716

The

notes on pages 24 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Cash Flows - (Unaudited )
Three months ended March 31,	2006	2005

(Thousands)
Operating Activities
Net income	$40,285	$30,928
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	33,952	34,167
Income taxes and investment tax credits deferred, net	9,293	10,858
Pension income	(3,514)	(4,513)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	(18,435)	(21,163)
Inventory	40,464	30,447
Prepayments and other current assets	(23,322)	(14,659)
Accounts payable and accrued liabilities	(23,828)	47,160
Interest accrued	(1,936)	(1,236)
Taxes accrued	14,144	8,736
Customer refund	(13,998)	(23,639)
Other current liabilities	(23,400)	(13,494)
Other assets	6,688	(3,979)
Other liabilities	(30,205)	2,606

Net Cash Provided by Operating Activities	6,188	82,219

Investing Activities
Utility plant additions	(13,508)	(9,868)
Maturity of current investments available for sale	137,950	102,825
Purchases of current investments available for sale	(84,625)	(147,850)
Other	(381)	108

Net Cash Provided by (Used in) Investing Activities	39,436	(54,785)

Financing Activities
Book overdraft	(1,671)	(1,658)
Dividends on common stock	(35,000)	(35,000)

Net Cash Used in Financing Activities	(36,671)	(36,658)

Net Increase (Decrease) in Cash and Cash Equivalents	8,953	(9,224)
Cash and Cash Equivalents, Beginning of Period	28,752	11,834

Cash and Cash Equivalents, End of Period	$37,705	$2,610

The

notes on pages 24 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Retained Earnings - (Unaudited)
Three months ended March 31,	2006	2005

(Thousands)
Balance, Beginning of Period	$28,549	$19,560
Add net income	40,285	30,928

	68,834	50,488
Deduct dividends on common stock	35,000	35,000

Balance, End of Period	$33,834	$15,488

The

notes on pages 24 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Comprehensive Income - (Unaudited)
Three months ended March 31,	2006	2005

(Thousands)
Net income	$40,285	$30,928
Other comprehensive income, net of tax
Net unrealized gains on investments, net of income tax (expense) of $(26) for 2006 and $ - for 2005	39	-
Net unrealized (losses) gains on derivatives qualified as hedges, net of income tax benefit (expense) of $826 for 2006 and $(1,586) for 2005	(1,246)	2,417
Reclassification adjustment for derivative losses (gains) included in net income, net of income tax (benefit) expense of $(2,011) for 2006 and $391 for 2005	3,033	(590)

Net unrealized gains on derivatives qualified as hedges	1,787	1,827

Total other comprehensive income	1,826	1,827

Comprehensive Income	$42,111	$32,755

The

notes on pages 24 through 29 are an integral part of the condensed financial statements.

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

New York State Electric & Gas Corporation
(a) Liquidity and Capital Resources
Restructuring
See Energy East's Item 2(a), Restructuring, for this discussion.
Electric Delivery Business
NYSEG's electric delivery business principally consists of its regulated transmission and distribution operations. It also generates electricity primarily from its hydroelectric stations.
Natural Gas Delivery Business
NYSEG's natural gas delivery business consists of its regulated transportation, storage and distribution operations.
Other Matters
Accounting Issues
FIN 46R
FASB Staff Position No. FAS 106-2
Investing and Financing Activities
Investing Activities:
Financing Activities
Management's discussion and analysis of financial condition and results of operations
New York State Electric & Gas Corporation
(b) Results of Operations
Three months ended June 30 2004 2003 Change
(Thousands)
Operating Revenues $428,495 $413,364 4%
Operating Income $70,935 $70,119 1%
Earnings Available for Common Stock $30,797 $29,824 3%
Second quarter 2004 earnings increased $1 million as compared to the prior year. An increase in earnings as a result of higher electricity deliveries due to weather was substantially offset by a decrease in earnings due to lower natural gas wholesale deliveries.
Six months ended June 30 2004 2003 Change
(Thousands)
Operating Revenues $1,020,709 $989,095 3%
Operating Income $172,158 $190,767 (10%)
Earnings Available for Common Stock $83,615 $90,342 (7%)
Earnings decreased $7 million for the six months primarily due to lower deliveries in the first quarter because of warmer winter weather in 2004.
Operating Results for the Electric Delivery Business
Three months ended June 30 2004 2003 Change
(Thousands)
Retail Deliveries - Megawatt-hours 3,472 3,362 3%
Operating Revenues $358,521 $338,353 6%
Operating Expenses $293,592 $276,011 6%
Operating Income $64,929 $62,342 4%
The $20 million increase in operating revenues for the quarter was primarily due to increased retail deliveries of $10 million and higher wholesale revenues of $9 million.
Operating expenses increased $18 million for the quarter primarily due to higher purchased power costs of $14 million as a result of higher retail and wholesale sales.
Management's discussion and analysis of financial condition and results of operations
New York State Electric & Gas Corporation
Six months ended June 30 2004 2003 Change
(Thousands)
Retail Deliveries - Megawatt-hours 7,448 7,408 1%
Operating Revenues $762,505 $744,320 2%
Operating Expenses $626,937 $600,753 4%
Operating Income $135,568 $143,567 (6%)
The $18 million increase in operating revenues for the six months was primarily due to higher retail deliveries of $4 million, increased wholesale revenues of $8 million and an $8 million increase in transmission revenues.
Operating expenses increased $26 million for the six months primarily due to higher purchased power costs of $21 million as a result of higher deliveries.
Operating Results for the Natural Gas Delivery Business
Three months ended June 30 2004 2003 Change
(Thousands)
Retail Deliveries - Dekatherms 10,096 11,301 (11%)
Operating Revenues $69,974 $75,011 (7%)
Operating Expenses $63,968 $67,234 (5%)
Operating Income $6,006 $7,777 (23%)
Operating revenues decreased $5 million for the quarter primarily as a result of an $8 million reduction due to lower retail deliveries and an $5 million decrease in wholesale revenues. Those decreases were partially offset by higher revenues of $8 million as a result of higher market prices that were passed on to customers.
Operating expenses decreased $3 million for the quarter, primarily due to lower natural gas purchases of $2 million.
Six months ended June 30 2004 2003 Change
(Thousands)
Retail Deliveries - Dekatherms 35,440 37,809 (6%)
Operating Revenues $258,204 $244,775 5%
Operating Expenses $221,614 $197,575 12%
Operating Income $36,590 $47,200 (22%)
Operating revenues increased $13 million for the six months primarily due to higher natural gas prices of $43 million that were passed on to customers. This increase was somewhat offset by a $15 million decrease because of lower wholesale sales, and a $15 million decrease due to lower retail deliveries because of warmer weather.
Operating expenses for the six months increased $24 million primarily due to higher natural gas purchases of $23 million; reflecting higher prices offset by lower purchase volumes.
Item 1.
Rochester Gas and Electric Corporation Condensed Statements of Income - (Unaudited)
Three Months Six Months
Periods ended June 30 2004 2003 2004 2003
(Thousands)
Operating Revenues
Electric $160,209 $166,384 $324,393 $342,678
Natural Gas 63,520 62,228 212,682 212,628
Total Operating Revenues 223,729 228,612 537,075 555,306
Operating Expenses
Electricity purchased and fuel used in generation 43,161 34,025 69,792 76,458
Natural gas purchased 35,092 33,545 134,174 131,250
Other operating expenses 34,266 64,846 90,736 155,328
Maintenance 13,183 14,017 28,461 27,450
Depreciation and amortization 31,984 25,688 67,977 52,913
Other taxes 18,929 19,457 38,969 43,792
Gain on sale of generation assets (319,487) - (319,487) -
Deferral of asset sale gain 214,368 - 214,368 -
Total Operating Expenses 71,496 191,578 324,990 487,191
Operating Income 152,233 37,034 212,085 68,115
Other (Income) (7,437) (423) (8,100) (2,541)
Other Deductions 1,570 815 1,943 963
Interest Charges, Net 13,696 12,405 27,800 46,387
Income Before Income Taxes 144,404 24,237 190,442 23,306
Income Taxes 115,475 9,564 135,573 7,143
Net Income 28,929 14,673 54,869 16,163
Preferred Stock Dividends 1,315 925 1,828 1,850
Earnings Available for Common Stock $27,614 $13,748 $53,041 $14,313
Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
June 30, 2004 Dec. 31, 2003
(Thousands)
Assets
Current Assets
Cash and cash equivalents $265,626 $13,596
Special deposits - 3,706
Accounts receivable, net 121,075 156,038
Advance to affiliate 25,000 -
Fuel, at average cost 28,727 29,310
Materials and supplies, at average cost 8,683 7,016
Accumulated deferred income tax benefits, net 20,831 12,154
Prepayments and other current assets 9,323 13,232
Total Current Assets 479,265 235,052
Utility Plant, at Original Cost
Electric 1,197,468 2,060,980
Natural gas 548,144 522,409
Common 174,283 158,804
1,919,895 2,742,193
Less accumulated depreciation 505,687 1,271,462
Net Utility Plant in Service 1,414,208 1,470,731
Construction work in progress 38,005 160,595
Total Utility Plant 1,452,213 1,631,326
Other Property and Investments, Net 13,280 287,385
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations 218,556 240,884
Unfunded future income taxes - 50,265
Environmental remediation costs 12,247 11,475
Unamortized loss on debt reacquisitions 3,541 -
Nonutility generator termination agreement 96,076 100,687
Asset retirement obligation - 163,530
Other 152,172 174,998
Total regulatory assets 482,592 741,839
Other assets
Prepaid pension benefits 28,033 16,524
Other 36,796 48,704
Total other assets 64,829 65,228
Total Regulatory and Other Assets 547,421 807,067
Total Assets $2,492,179 $2,960,830
Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
June 30, 2004 Dec. 31, 2003
(Thousands)
Liabilities
Current Liabilities
Current portion of preferred stock subject to mandatory redemption requirements - $1,250
Accounts payable and accrued liabilities $131,065 77,476
Interest accrued 10,552 11,540
Taxes accrued 71,976 24,130
Other 52,806 29,642
Total Current Liabilities 266,399 144,038
Regulatory and Other Liabilities
Regulatory liabilities
Unfunded future income taxes 87,379 -
Accrued removal obligation 169,618 185,472
Deferred income taxes 5,471 186,571
Gain from sale of generation assets 127,403 -
Other 37,851 46,173
Total regulatory liabilities 427,722 418,216
Other liabilities
Deferred income taxes 170,865 72,568
Nuclear waste disposal 104,699 104,095
Other postretirement benefits 73,664 71,956
Environmental remediation costs 26,357 22,356
Asset retirement obligation 2,171 436,096
Other 45,925 39,831
Total other liabilities 423,681 746,902
Total Regulatory and Other Liabilities 851,403 1,165,118
Preferred stock subject to mandatory redemption requirements - 23,750
Other long-term debt 736,563 826,511
Total long-term debt 736,563 850,261
Total Liabilities 1,854,365 2,159,417
Commitments - -
Preferred Stock
Redeemable solely at the option of RG&E - 47,000
Common Stock Equity
Common stock 194,429 194,429
Capital in excess of par value 556,550 556,190
Retained earnings 4,073 121,032
Treasury stock, at cost (117,238) (117,238)
Total Common Stock Equity 637,814 754,413
Total Liabilities and Stockholder's Equity $2,492,179 $2,960,830
Rochester Gas and Electric Corporation Condensed Statements of Cash Flows - (Unaudited)
Six months ended June 30 2004 2003
(Thousands)
Net Cash Provided by Operating Activities $85,551 $139,955
Investing Activities
Proceeds from sale of generation assets 428,541 -
Refund of excess decommissioning fund 76,593 -
Advance to affiliate (25,000) -
Utility plant additions (32,361) (40,044)
Nuclear generating plant decommissioning fund (8,560) (8,662)
Other 3,706 (2,052)
Net Cash Provided by (Used in) Investing Activities 442,919 (50,758)
Financing Activities
Repayments of first mortgage bonds and preferred stock (162,000) (40,000)
Outstanding customer refund, overdraft 57,388 -
Repayment of promissory notes - (79,935)
Dividends on common and preferred stock (171,828) (31,850)
Net Cash Used in Financing Activities (276,440) (151,785)
Net Increase (Decrease) in Cash and Cash Equivalents 252,030 (62,588)
Cash and Cash Equivalents, Beginning of Period 13,596 86,385
Cash and Cash Equivalents, End of Period $265,626 $23,797
Rochester Gas and Electric Corporation Condensed Statements of Retained Earnings - (Unaudited)
Six months ended June 30 2004 2003
(Thousands)
Balance, Beginning of Period $121,032 $154,267
Add net income 54,869 16,163
175,901 170,430
Deduct Dividends on Capital Stock
Preferred 1,828 1,850
Common 170,000 30,000
171,828 31,850
Balance, End of Period $4,073 $138,580
Item 2.
Rochester Gas and Electric Corporation

RG&E's Management's Discussion and Analysis of Financial Condition and Results of Operations for the quarter ended March 31, 2006, should be read in conjunction with its Management's Discussion and Analysis of Financial Condition and Results of Operations, financial statements and notes contained in its report on Form 10-K for the fiscal year ended December 31, 2005. Due to the seasonal nature of RG&E's operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Electric Delivery Business Developments

RG&E's electric delivery business consists of its regulated electricity transmission and distribution operations in western New York. It also generates electricity from its one coal-fired plant, three gas turbines and several smaller hydroelectric stations.

Niagara Power Project Relicensing: See Energy East's Part I, Item 2 - MD&A - Electric Delivery Business Developments - Niagara Power Project Relicensing, for this discussion.

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: See Energy East's Part I, Item 2 - MD&A - Electric Delivery Business Developments, for this discussion.

Natural Gas Delivery Business Developments

RG&E's natural gas delivery business consists of its regulated transportation, storage and distribution operations in western New York.

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: See Energy East's Part I, Item 2 - MD&A - Electric Delivery Business Developments, for this discussion.

Proposed New Accounting Standard

Pension Exposure Draft: See Energy East's Part I, Item 2 - MD&A - Proposed New Accounting Standard, for this discussion.

(a) Liquidity and Capital Resources

~~Restructuring~~Operating Activities
: Cash flows from operating activities included refunds to RG&E customers of $15 million in 2006 and $25 million in 2005, from proceeds from the sale of Ginna, pursuant to the Electric Rate Agreement. The Electric Rate Agreement requires an additional refund to customers of $10 million in 2007.

See Energy East's Item 2(a), Restructuring, for this discussion.
Electric Delivery Business
RG&E's electric delivery business consists of its regulated transmission and distribution operations. It also generates electricity from its one coal-fired plant, three gas turbines and several smaller hydroelectric stations.
Natural Gas Delivery Business
RG&E's natural gas delivery business consists of its regulated transportation, storage and distribution operations.
Other Matters
Accounting Issues
FASB Staff Position No. FAS 106-2
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Investing and Financing Activities
Investing Activities
: Capital spending for the first three months of 2006 was $14 million. RG&E projects capital spending of $182 million for 2006 and expects to pay for it principally with cash on hand and 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 a transmission project and a new customer care system.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Rochester Gas and Electric Corporation

Financing Activities
: During the three months ended March 31, 2006, RG&E paid a common dividend of $35 million.

(b) Results of Operations

Three months ended June 30	2004	2003	Change
Three months ended March 31,	2006	2005
(Thousands)
Operating Revenues	$~~223~~346,~~729~~511	$~~228~~315,~~612~~720	~~(2%)~~
Operating Income	$~~152~~77,~~233~~168	$3764,~~034~~878	~~311%~~
Earnings Available for Common Stock	$27,614	$13,748	101%
Net Income	$40,285	$30,928

Earnings increased $14 million for the quarter primarily due to one-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements, which increased earnings $10 million. The one-time effects include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory determination. Ongoing effects from RG&E's Electric and Natural Gas Rate Agreements added $7 million to earnings, and include increases as a result of RG&E's electric retail access surcharge and natural gas merchant function charge, and annual credits to RG&E from the ASGA as provided in the Electric Rate Agreement. (See

Six months ended June 30	2004	2003	Change
(Thousands)
Operating Revenues	$537,075	$555,306	(3%)
Operating Income	$212,085	$68,115	211%
Earnings Available for Common Stock	$53,041	$14,313	271%

RG&E's net income for the quarter ended March 31, 2006, increased $9 million compared to the quarter ended March 31, 2005, primarily because of higher net margins on electricity sales.

Earnings for the six months increased $39 million primarily due to the second quarter effects of the sale of Ginna and RG&E's Electric and Natural Gas Rate Agreements discussed above that added $17 million to earnings and the recognition of the terms and conditions of the NYPSC rate order for RG&E, which became effective in January 2003, and reduced earnings by $30 million in the first quarter of 2003. The January 2003 rate order included $26 million for excess earnings and related interest.
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Operating Results for the Electric Delivery Business

Three months ended June 30	2004	2003	Change
Three months ended March 31,	2006	2005
(Thousands)
Retail Deliveries - Megawatt-hours	1,699	1,669	2%
Retail Deliveries (MWh)	1,748	1,755
Operating Revenues	$160,209	$166,384	(4%)
Retail Commodity Sales (MWh) (1)	897	1,021
Operating Expenses	$14,603	$136,048	(89%)
Wholesale sales (MWh)	1,008	557
Operating Income	$145,606	$30,336	380%
Operating Revenues	$185,638	$160,156
Operating Expenses	$137,521	$122,449
Operating Income	$48,117	$37,707

^{The $6 million decrease in operating revenues for the quarter is primarily due to a change in market structure that allows ESCOs to provide electricity, which reduced retail revenues by $41 million and increased wholesale revenues by $27 million. That decrease was partially offset by higher retail deliveries that added $3 million to revenues. (1)} Also included in Retail Deliveries.

Operating expenses decreased $121 million for the quarter primarily due to RG&E's recognition of a $319 million pretax gain on the Ginna sale, partially offset by RG&E's deferral of the gain net of tax of $214 million. The remaining $16 million reduction was primarily the result of lower electricity purchases as a result of the change in market structure and the net effects of the Ginna sale that reduced operating expenses and increased purchased power costs. Revenues
: The $25 million increase in operating revenues for the first quarter of 2006 was primarily the result of:

Six months ended June 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	3,439	3,450	-
Operating Revenues	$324,393	$342,678	(5%)
Operating Expenses	$144,345	$309,196	(53%)
Operating Income	$180,048	$33,482	438%

An increase of $25 million due to higher wholesale revenues,
~~Operating~~An ~~revenues~~increase ~~for~~of ~~the six months decreased~~ $1822 million due ato ~~change~~higher in market ~~structure~~prices ~~that~~for ~~allows ESCOs to provide electricity, which reduced~~ retail ~~revenues~~deliveries bysupplied ~~$77~~under ~~million~~various ~~and~~commodity ~~increased~~options ~~wholesale~~where ~~revenues~~RG&E byprovides ~~$55~~supply, ~~million.~~ and
~~Operating~~An ~~expenses~~increase ~~decreased~~of $~~165~~15 million ~~for~~in ~~the~~other ~~six~~revenues ~~primarily~~including ~~due to RG&E's recognition of~~ a ~~$319~~reduction ~~million pretax gain on the Ginna sale, partially offset by RG&E's deferral~~ of ~~the gain net of tax of~~ $~~214~~9 million. Anin ~~additional decrease of $30 million resulted from~~ the ~~recognition of the terms and conditions of the NYPSC rate order~~ accrual for ~~RG&E,~~earnings ~~which~~sharing ~~became~~reflecting ~~effective in January 2003, and increased operating expenses by $30 million in 2003. The remaining $25 million reduction was primarily~~ the ~~result~~finalization of ~~lower electricity purchases as a result of~~ the ~~change~~actual inamount ~~market~~for ~~structure,~~2005 ~~and~~per the ~~net~~annual ~~effects~~compliance ~~of the Ginna sale that reduced operating expenses and increased purchased power costs~~filing.

~~Management's~~Those ~~discussion~~increases ~~and~~were ~~analysis~~partially ofoffset ~~financial condition and results of operations~~by:

A decrease of $37 million resulting from lower average prices on deliveries. Higher market prices for electric entitlements are passed through to customers through a lower transition charge. The transition charge reflects the difference between the market price of electricity and the prices set by RG&E's long-term electricity supply contracts. This charge decreases as market prices increase. Changes in the transition charge have no effect on earnings.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Rochester Gas and Electric Corporation
Operating Expenses
: The $15 million increase in operating expenses for the first quarter of 2006 was primarily the result of:

An increase of $12 million for purchased power costs, and
An increase of $2 million for other taxes.

Operating Results for the Natural Gas Delivery Business

Three months ended June 30	2004	2003	Change
Three months ended March 31,	2006	2005
(Thousands)
Retail Deliveries - Dekatherms	8,529	9,314	(8%)
Retail Deliveries (Dth)	20,397	23,700
Operating Revenues	$63160,~~520~~873	$62155,~~228~~564	2%
Operating Expenses	$56131,~~893~~822	$55128,~~530~~393	2%
Operating Income	$629,~~627~~051	$627,~~698~~171	~~(1%)~~

Operating revenues increased $1 million for the quarter. Higher market prices for natural gas purchased of $9 million that were passed on to customers were offset by lower deliveries that reduced revenues $7 million. Revenues
: The $5 million increase in operating revenues for the first quarter of 2006 was primarily the result of:

~~Operating~~Higher ~~expenses increased $1 million for the quarter primarily due to higher market prices for purchased~~ natural gas prices that were ~~offset~~passed byon ~~fewer~~to ~~purchases because of lower deliveries~~customers.

Six months ended June 30 2004 2003 Change
(Thousands)
Retail Deliveries - Dekatherms 32,677 34,347 (5%)
Operating Revenues $212,682 $212,628 -
Operating Expenses $180,645 $177,995 1%
Operating Income $32,037 $34,633 (7%)
Operating Expenses
: The $3 million increase in operating expenses for the first quarter of 2006 was primarily the result of:

~~Operating revenues remained relatively flat for the six months.~~ Higher ~~market~~ prices for ~~natural gas~~ purchased ofnatural ~~$13 million that were passed on to customers were offset by lower deliveries that reduced revenues $13 million~~gas.

Operating expenses increased $3 million for the quarter primarily due to higher market prices for purchased natural gas that were offset by lower operating costs.
Item 1.
Financial Statements
Notes to Condensed Financial Statements for Energy East Corporation ~~Central~~ ~~Maine Power Company~~ ~~New York State Electric & Gas Corporation~~and Rochester Gas and Electric Corporation

Notes to Condensed Financial Statements of Registrants:

Registrant	Applicable Notes
Energy East	1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11
CMP	1, 3, 4, 7, 8, 9, 10, 11
RG&E	1, 2, 4, 6, 8, 9, 10, 11
NYSEG	1, 3, 4, 7, 8, 9, 10, 11
RG&E	1, 2, 3, 4, 8, 9, 10, 11

Note 1. Unaudited Condensed Financial Statements

~~The~~In the opinion of each registrant's management, the accompanying unaudited condensed financial statements reflect all adjustments necessary, ~~in the opinion of the management of the registrants,~~ for a fair ~~presentation~~statement of the interim ~~results~~periods presented. All such adjustments are of a normal, recurring nature. The year-end condensed balance sheet data presented ~~in this quarterly report~~ was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Energy East's financial statements ~~and CMP's financial statements~~ consolidate ~~their~~its majority-owned subsidiaries after eliminating all intercompany transactions.

The accompanying unaudited financial statements for each registrant should be read in conjunction with the financial statements and notes contained in the report on Form 10-K filed by each registrant for the fiscal year ended December 31, ~~2003~~2005. Due to the seasonal nature of the registrants' operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Reclassifications
: Certain amounts have been reclassified in the companies' unaudited financial statements to conform to the 2006 presentation.

~~Note~~Effective 2December 31, 2005, Energy East and RG&E revised the presentation of their investments in auction rate securities, classifying them as current investments available for sale rather than as cash and cash equivalents. ~~Sale~~Energy East held current investments of ~~Ginna~~$12 ~~Nuclear~~million ~~Generating~~at ~~Station~~March 31, 2006, and $193 million at December 31, 2005, which consisted of auction rate securities classified as available for sale. RG&E held no current investments at March 31, 2006, and $53 million at December 31, 2005. Investments in these securities are recorded at cost, which approximates fair market value due to their variable interest rates. Energy East and RG&E have no cumulative unrealized or realized gains or losses from their current investments. All income generated from these current investments is recorded as interest income.

OnNote ~~June 10, 2004, after receiving all regulatory approvals, RG&E sold Ginna to CGG~~2. ~~RG&E~~Other ~~received~~(Income) atand ~~closing~~Other ~~$429~~Deductions ~~million in cash. The gain on the sale of Ginna of $319 million net of income taxes of $105 million equals the $214 million deferral of asset sale gain, as reflected on RG&E's statement of income.~~

RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna, including providing for an ASGA, established at the time of closing in the amount of $357 million, and addressing the disposition of the asset sale gain. Upon closing of the Ginna sale, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. RG&E retained $77 million in excess decommissioning funds, which was credited to customers as part of the ASGA.

Three months ended March 31,	2006	2005

(Thousands)
Energy East
Interest and dividend income	$(3,776)	$(2,350)
Allowance for funds used during construction	(489)	(306)
Gains from hedge activity	(2,438)	(1,920)
Earnings from equity investments	(1,059)	(1,149)
Miscellaneous	(2,638)	(2,099)

Total other (income)	$(10,400)	$(7,824)

Losses from hedge activity	$2,324	-
Donations, civic and political	848	$638
Miscellaneous	845	1,337

Total other deductions	$4,017	$1,975

RG&E
Interest and dividend income	$(707)	$(518)
Allowance for funds used during construction	(332)	(54)
Gains from hedge activity	-	(842)
Miscellaneous	(25)	(140)

Total other (income)	$(1,064)	$(1,554)

Miscellaneous	$182	$128

Total other deductions	$182	$128

ANote ~~summary~~3. ofBasic ~~information on the sale of Ginna~~ and ~~the~~Diluted ~~related~~Earnings ~~ASGA~~per ~~at the time of the sale follows (in thousands):~~Share

Cash proceeds	$428,541
Net book value of property sold, excluding decommissioning reserve	(184,564)
Decommissioning reserve	311,571
Decommissioning funds	(277,113)
Excess decommissioning funds retained	76,593
Miscellaneous assets and liabilities, including deferred selling costs	(35,541)
Gain on sale of generation assets, deferred	319,487
Income taxes payable	(105,119)
Deferral of asset sale gain	214,368
Regulatory liability equal to deferred income taxes on the deferred asset sale gain	143,000
Balance at closing, Gain from sale of generation assets, deferred	$357,368

We determine basic EPS by dividing net income by the weighted-average number of shares of common stock outstanding during the period. The weighted-average common shares outstanding for diluted EPS include the incremental effect of restricted stock and stock options issued and exclude stock options issued in tandem with SARs. Historically, we have issued stock options in tandem with SARs and substantially all stock option plan participants have exercised the SARs instead of the stock options. The numerator we use in calculating both basic and diluted EPS for each period is our reported net income.

The ASGA was adjusted subsequent to the sale to reflect provisions of RG&E's Electric Rate Agreement, including refunds due to customers. Adjustments to the ASGA to reconcile to the balance of the deferred regulatory liability as of June 30, 2004, were as follows (in thousands):

Gain from sale of generation assets, deferred	$357,368
Regulatory liability equal to deferred income taxes on the deferred asset sale gain	(143,000)
Refund to customers June 2004	(60,003)
Refund to customers January 2005 - Other current liability	(24,997)
Other	(1,965)
Balance at June 30, 2004, Gain from sale of generation assets	$127,403

In addition, the company's and RG&E's effective tax rate was significantly affected by the sale of Ginna. Due to the regulatory accounting for the gain on the sale, any gain in excess of what was required to offset income taxes payable on the sale was required to be deferred. Therefore, RG&E recorded pretax income of $105,119 and income tax expense of $105,119 resulting in a 100% effective tax rate on this income, increasing the effective tax rate from an expected rate of 39% for the company and 41% for RG&E, to an effective rate of 56% for the company and 71% for RG&E.

Note 3. Restructuring

The company recognized a $4 million total liability for an enhanced severance program for 83 accounting and finance employees who were employed through March 31, 2004. During the fourth quarter of 2003, 40%, or approximately $2 million, of the estimated liability was charged to other operating expenses and represented the company's cumulative expense and liability as of December 31, 2003. The remaining $2 million of the liability was charged to other operating expenses in the first quarter of 2004. The total liability includes $0.9 million for CMP, $0.9 million for NYSEG and $1.4 million for RG&E. Approximately $3 million of the total cost was incurred by the electric delivery business and $1 million by the natural gas delivery business. The liability was paid off as of June 30, 2004.

Note 4. Other (Income) and Other Deductions

	Three Months		Six Months
Periods ended June 30	2004	2003	2004	2003
(Thousands)
Energy East
Interest income	$(959)	$(1,086)	$(1,365)	$(2,355)
Allowance for funds used during construction	(160)	(422)	(262)	(966)
Gains from the sale of nonutility property	(1,159)	(5)	(1,236)	(59)
Earnings from equity investments	(852)	(884)	(2,557)	(2,542)
2003 RG&E Electric and Natural Gas Rate Agreement	(6,117)	-	(6,117)	-
Miscellaneous	(2,434)	119	(5,872)	(888)
Total other (income)	$(11,681)	$(2,278)	$(17,409)	$(6,810)
Losses from disposition of property	$3,474	-	$4,048	-
Miscellaneous	924	$1,261	3,627	$3,048
Total other deductions	$4,398	$1,261	$7,675	$3,048
CMP
Interest income	$(20)	$(162)	$(34)	$(418)
Earnings from equity investments	(217)	(480)	(513)	(1,018)
Miscellaneous	(795)	(119)	(1,536)	(312)
Total other (income)	$(1,032)	$(761)	$(2,083)	$(1,748)
Miscellaneous	$164	$420	$299	$799
Total other deductions	$164	$420	$299	$799
NYSEG
Interest income	$(58)	$(274)	$(119)	$(652)
Miscellaneous	(158)	90	(53)	(1,456)
Total other (income)	$(216)	$(184)	$(172)	$(2,108)
Miscellaneous	$454	$(1,553)	$172	$(1,297)
Total other deductions	$454	$(1,553)	$172	$(1,297)
RG&E
Interest income	$(794)	$(236)	$(462)	$(1,947)
2003 RG&E Electric and Natural Gas Rate Agreement	(6,117)	-	(6,117)	-
Miscellaneous	(526)	(187)	(1,521)	(594)
Total other (income)	$(7,437)	$(423)	$(8,100)	$(2,541)
Losses from disposition of property	$3,158	-	$3,158	-
Miscellaneous	(1,588)	$815	(1,215)	$963
Total other deductions	$1,570	$815	$1,943	$963

Note 5. Basic and Diluted Earnings per Share

Basic earnings per share (EPS) is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the period. The weighted-average common shares outstanding for diluted EPS include the incremental effect of restricted stock and stock options issued and exclude stock options issued in tandem with stock appreciation rights (SARs). However, all stock options are issued in tandem with SARs and, historically, substantially all stock option plan participants have exercised the SARs instead of the stock options. The numerator used in calculating both basic and diluted EPS for each period is the reported net income.

The reconciliation of basic and dilutive average common shares for each period follows:

	Three Months		Six Months
Three months ended March 31,	2006	2005
Periods ended June 30	2004	2003	2004	2003
(Thousands)
(Thousands)
Basic average common shares outstanding	147,034	146,875
Basic average common shares outstanding	146,148	145,415	146,116	145,256
Restricted stock awards	645	321
Restricted stock awards	448	225	396	173
Potentially dilutive common shares	144	416
Potentially dilutive common shares	302	107	266	127
Options issued with SARs	(144)	(416)
Options issued with SARs	(302)	(107)	(266)	(127)
Dilutive average common shares	147,679	147,196
Dilutive average common shares outstanding	146,596	145,640	146,512	145,429

~~Options~~We toexclude ~~purchase shares of common stock are excluded~~ from the determination of EPS ~~when~~options ~~the~~that have an exercise price ofthat ~~an option~~ is greater than the average market price of athe common ~~share~~shares during the period. Shares excluded from the EPS calculation for the three months ended ~~June~~March 3031 were: 01.~~7 million in 2004 and~~ 5.2 million in ~~2003,~~2006 and ~~for the six months ended June 30 were: 1~~0.3 9 million in ~~2004 and 5~~2005.~~2 million in 2003.~~

~~During~~Note the first quarter of 2004 the company awarded 242,038 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of $6 million based on the market price per share of common stock on the dates of the awards, which averaged $234.~~90.~~ Income Taxes

~~Note~~RG&E's 6effective tax rate for the first quarter of 2006 is lower than the statutory rate, primarily due to the flow-through effect of equity AFUDC in the determination of the projected 2006 annual effective rate. ~~Discontinued~~The ~~Operations~~projected tax adjustment for equity AFUDC is approximately $7 million and is larger than in recent years because of RG&E's transmission project.

InNote ~~keeping with its focus on regulated electric and natural gas delivery businesses, during recent years the company has been systematically exiting certain noncore businesses~~5. InVariable ~~June~~Interest 2004 UWP, a subsidiary of CMP Group, Inc., reached an agreement to sell the assets associated with its utility locating and construction divisions. The sale was completed on July 26, 2004. In 2003 Berkshire Propane, Inc., a subsidiary of Berkshire Energy Resources, sold its assets and Energetix, a subsidiary of RGS Energy Group, Inc. which is a wholly-owned subsidiary of Energy East, sold its Griffith Oil Co., Inc. All three businesses were previously reported in the company's Other business segment. Certain financial information concerning the businesses for the three months and six months ended June 30, 2004 and 2003, is shown in the table below. Entities

	Three Months		Six Months
Periods ended June 30	2004	2003	2004	2003
(Thousands)
Certain Divisions of Union Water Power Co.
Revenues	$8,157	$6,969	$13,175	$10,432
Income (loss) from businesses held for sale (including estimated loss on disposal in 2004 of $5,500)	$(4,249)	$619	$(4,527)	$(1,375)
Income taxes (benefits)	467	100	346	(712)
Income (loss) from discontinued operations	$(4,716)	$519	$(4,873)	$(663)
Griffith Oil Co., Inc.
Revenues	-	$83,922	-	$211,544
Income (loss) from businesses sold	-	$(1,503)	-	$5,916
Income taxes (benefits)	-	(671)	-	2,107
Income (loss) from discontinued operations	-	$(832)	-	$3,809
Berkshire Propane, Inc.
Revenues	-	$1,041	-	$4,472
Income (loss) from businesses sold	-	$(17)	-	$517
Income taxes	-	286	-	506
Income (loss) from discontinued operations	-	$(303)	-	$11

A variable interest entity is an entity that is not controllable through voting interests and/or in which the equity investor does not bear the residual economic risks and rewards. A business enterprise is required to consolidate a variable interest entity if the enterprise has a variable interest that will absorb a majority of the entity's expected losses.

~~Note~~We 7have independent, ongoing, power purchase contracts with NUGs. ~~FIN~~However, ~~46R~~we were not involved in the formation of and do not have ownership interests in any NUGs. We have evaluated all of our power purchase contracts with NUGs and determined that most of the power purchase contracts are not variable interests for one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUG is a governmental organization or an individual. We are not able to determine if we have variable interests with respect to power purchase contracts with seven of the NUGs because we are unable to obtain the information necessary to (1) determine if any of the seven NUGs is a variable interest entity, (2) determine if an operating utility is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of those NUGs. We routinely request necessary information from the seven NUGs, and will continue to do so, but no NUG has yet provided the requested information. We did not consolidate any NUGs as of March 31, 2006, or December 31, 2005.

InWe ~~December~~purchase ~~2003~~electricity from the ~~FASB~~seven ~~issued~~NUGs ~~its~~at ~~revised~~above-market ~~FASB~~prices. ~~Interpretation~~We ~~No.~~are ~~46,~~not ~~Consolidation~~exposed ofto ~~Variable~~any ~~Interest~~loss ~~Entities,~~as ana ~~interpretation~~result of ~~ARB~~our ~~No.~~involvement 51with ~~(FIN~~the ~~46R).~~NUGs ~~FIN~~because ~~46R~~we ~~addresses~~are ~~consolidation~~allowed ofto ~~variable~~recover ~~interest~~through ~~entities.~~rates Athe ~~variable~~cost ~~interest~~of ~~entity~~our ispurchases. anAlso, ~~entity~~we ~~that~~are isunder ~~not~~no ~~controllable~~obligation ~~through~~to ~~voting~~a ~~interests~~NUG ~~and/or~~if init ~~which~~decides ~~the equity investor does~~ not ~~bear~~to ~~the~~operate ~~residual~~for ~~economic~~any ~~risks and rewards~~reason. ~~FIN~~The ~~46R~~combined ~~requires~~contractual acapacity ~~business~~for ~~enterprise~~the toseven ~~consolidate~~NUGs ais ~~variable~~approximately ~~interest~~517 ~~entity~~MWs. ifThe ~~that~~combined ~~enterprise~~purchases ~~has~~from athe ~~variable~~seven ~~interest~~NUGs ~~that~~totaled ~~will~~approximately ~~absorb~~$91 amillion ~~majority~~for of the ~~entity's~~three ~~expected~~months ~~losses.~~ended ~~The~~March ~~company~~31, ~~was~~2006, ~~required~~and to$94 ~~apply~~million ~~FIN~~for ~~46R to all entities subject to~~ the ~~interpretation~~three asmonths ofended March 31, ~~2004~~2005.

~~CMP~~Note ~~and NYSEG have independent, ongoing, power purchase contracts with various nonutility generators (NUGs)~~6. ~~(See report on Form 10-K for Energy East, CMP and NYSEG for fiscal year ended December 31, 2003, Item 7 - Liquidity and Capital Resources, Contractual Obligations and Commercial~~ Commitments.) ~~CMP~~ and NYSEG were not involved in the formation of and do not have ownership interests in any NUGs. The company evaluated each of CMP's and NYSEG's power purchase contracts with NUGs with respect to FIN 46R. Most of the power purchase contracts were determined not to be variable interests due to one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUGs are either governmental organizations or individuals. Contingencies

~~The~~NYISO ~~companies~~billing are not able to apply FIN 46R to seven remaining NUGs because they are unable to obtain the information necessary to: (1) determine if the NUGs are variable interest entities, (2) determine if either CMP or NYSEG is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of the seven NUGs. CMP requested necessary information from four NUGs and NYSEG requested information from three NUGs. Three of the NUGs responded but none provided the requested information. The companies will continue to make efforts to obtain information, including from the four NUGs that did not respond to the request. adjustment
: The NYISO frequently bills market participants on a retroactive basis when it determines that billing adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission or supply revenue or expense, as appropriate, when revised amounts are available. The two companies have developed an accrual process that incorporates available information about retroactive NYISO billing adjustments as provided to all market participants. However, on an ongoing basis, they cannot fully predict either the magnitude or the direction of any final billing adjustments.

~~The~~Note companies purchase electricity from the seven NUGs at above-market prices. CMP and NYSEG are not exposed to any loss as a result of their involvement with NUGs because they are allowed to recover through rates the cost of their purchases. Also, they are under no obligation to a NUG if it decides not to operate for any reason. The combined contractual capacity for the four NUGS from which CMP purchases electricity is approximately 22 MW. CMP's purchases from the four NUGs totaled $7 ~~million for the six months ended June 30, 2004, and $5 million for the six months ended June 30, 2003~~. ~~The~~Share-Based combined contractual capacity for the three NUGS from which NYSEG purchases electricity is approximately 494 MW. NYSEG's purchases from the three NUGs totaled $172 million for the six months ended June 30, 2004, and $169 million for the six months ended June 30, 2003.Compensation

~~CMP~~We early adopted Statement 123(R) effective October 1, 2005, using the modified version of prospective application. Statement 123(R) is a revision of Statement 123 and ~~NYSEG~~requires ~~did~~a ~~not~~public ~~consolidate~~entity ~~any~~to ~~NUGs~~measure asthe cost of ~~June~~employee 30services that it receives in exchange for an award of equity instruments based on the grant-date fair value of the award and recognize that cost over the period during which the employee is required to provide service in exchange for the award. Statement 123(R) also requires a public entity to initially measure the cost of employee services received in exchange for an award of liability instruments (e.g., ~~2004~~instruments that are settled in cash) based on the award's current fair value, subsequently remeasure the fair value of the award at each reporting date through the settlement date and recognize changes in fair value during the required service period as compensation cost over that period.

We incur a liability for our stock option plan awards in accordance with Statement 123(R) because our policy is to grant SARs in tandem with any stock options and employees can request that the awards be settled in cash rather than by issuing equity instruments. Prior to our adoption of Statement 123(R), we applied APB 25, as permitted by Statement 123, to account for our stock-based compensation to employees. We also incurred a liability for our stock options/SARs under ABP 25, but we used the intrinsic value method to determine our liability and the related compensation cost. Statement 123 required the amount of the liability for awards that call for settlement in cash to be measured each period based on the current stock price, which produced the same result as using the intrinsic value method under APB 25 for such awards. Compensation for shares granted under our Restricted Stock Plan is determined using the grant-date fair value of shares awarded, which is based on the market price of Energy East's common stock on the date of the restricted stock award and is not subsequently remeasured.

Share-based compensation, net of related tax effects, was $0.1 million for the quarter ended March 31, 2005, and that amount was the same as if the fair value based method in accordance with Statement 123 had been applied to all awards. Net income and basic and diluted earnings per share as reported for the quarter ended March 31, 2005, are no different than as if the fair value based method had been applied. Share-based compensation, net of related tax effects, for the quarter ended March 31, 2006, was $3.9 million.

Note 8. Accounts Receivable

~~Accounts~~Energy ~~receivable~~East's ~~for~~accounts ~~the~~receivable ~~companies~~ include unbilled revenues ~~as follows: Energy East - consolidated unbilled revenues~~ of $86233 million at ~~June 30~~March 31, ~~2004~~2006, and $~~219~~315 million at December 31, ~~2003;~~2005. ~~CMP~~Our -accounts ~~consolidated~~receivable ~~unbilled~~are ~~revenues~~shown net of ~~$13~~an ~~million~~allowance atfor ~~June~~doubtful ~~30,~~accounts ~~2004, and $25 million at December 31, 2003; NYSEG - unbilled revenues~~ of $4358 million at ~~June~~March ~~30, 2004, and $72 million at December~~ 31, ~~2003; RG&E - unbilled revenues of $20 million at June 30~~2006, ~~2004,~~ and $5053 million at December 31, ~~2003~~ 2005.

RG&E's accounts receivable include unbilled revenues of $46 million at March 31, 2006, and $54 million at December 31, 2005. RG&E's accounts receivable are shown net of an allowance for doubtful accounts of $14 million at March 31, 2006, and $13 million at December 31, 2005.

Note 9. Retirement Benefits

Components of net periodic benefit (income) cost

	Pension Benefits		Postretirement Benefits
Three months ended June 30	2004	2003	2004	2003
Three months ended March 31,	2006	2005	2006	2005
(Thousands)
Energy East
Service cost	$79,~~807~~198	$79,~~606~~285	$1,~~407~~567	$1,~~501~~549
Interest cost	32,~~931~~433	3332,~~008~~031	87,~~987~~879	97,~~446~~980
Expected return on plan assets	(5154,~~742~~878)	(5152,~~309~~910)	(~~672~~483)	(~~786~~556)
Amortization of prior service cost	1,~~161~~176	1,~~246~~249	(1,~~713~~895)	(1,~~723~~895)
Recognized net actuarial (gain) loss	(210)	(596)	1,583	2,254
Recognized net actuarial loss	4,605	3,952	2,076	2,635
Amortization of transition (asset) obligation	(307)	(1,809)	1,984	2,016
Amortization of transition obligation	-	-	1,700	1,700
Curtailment	-	202	-	(307)
Net periodic benefit (income) cost	$(7,466)	$(6,393)	$10,844	$11,413
Net periodic benefit cost	$(10,360)	$(11,652)	$11,576	$12,401
CMP
Service cost	$1,017	$1,107	$353	$399
Interest cost	3,506	3,429	2,067	1,976
Expected return on plan assets	(3,852)	(3,688)	(265)	(379)
Amortization of prior service cost	50	61	(157)	(164)
Recognized net actuarial (gain) loss	1,277	1,103	695	539
Curtailment	-	202	-	(307)
Net periodic benefit cost	$1,998	$2,214	$2,693	$2,064
NYSEG
Service cost	$4,471	$4,053	$793	$777
Interest cost	17,421	17,072	4,506	5,012
Expected return on plan assets	(30,968)	(30,231)	-	-
Amortization of prior service cost	1,084	1,166	(1,532)	(1,540)
Recognized net actuarial (gain) loss	(2,758)	(4,071)	808	1,431
Amortization of transition (asset) obligation	(307)	(1,809)	1,983	2,016
Net periodic benefit cost	$(11,057)	$(13,820)	$6,558	$7,696
RG&E
Service cost	$1,~~234~~171	$1,~~572~~339	$~~243~~166	$~~292~~272
Interest cost	76,~~435~~825	86,~~086~~803	1,~~502~~107	1,~~562~~444
Expected return on plan assets	(1211,~~136~~490)	(12,~~823~~021)	-	-
Unrecognized transition obligation	-	-	514	621
Amortization of prior service cost	370	280	215	250
Amortization of prior service cost	306	365	277	335
Recognized net actuarial (gain) loss	(390)	(914)	(343)	133
Recognized net actuarial (gain) loss	(1,788)	(2,062)	(110)	(69)
Amortization of transition obligation	-	-	457	464
Net periodic benefit cost	$(4,949)	$(4,862)	$2,426	$2,741
Net periodic benefit (income) cost	$(3,514)	$(4,513)	$1,602	$2,563

Pension Benefits Postretirement Benefits
Six months ended June 30 2004 2003 2004 2003
(Thousands)
Energy East
Service cost $16,055 $15,608 $3,250 $3,343
Interest cost 65,492 66,245 18,369 18,356
Expected return on plan assets (103,060) (102,087) (1,336) (1,400)
Amortization of prior service cost 2,325 2,493 (3,424) (3,440)
Recognized net actuarial (gain) loss (535) (3,093) 3,795 3,365
Amortization of transition (asset) obligation (615) (3,619) 4,001 4,033
Curtailment - 202 - (307)
Net periodic benefit cost $(20,338) $(24,251) $24,655 $23,950
CMP
Service cost $2,118 $2,206 $839 $907
Interest cost 6,968 6,787 4,110 3,957
Expected return on plan assets (7,444) (7,053) (520) (582)
Amortization of prior service cost 99 109 (314) (321)
Recognized net actuarial (gain) loss 2,420 2,000 1,271 1,047
Curtailment - 202 - (307)
Net periodic benefit cost $4,161 $4,251 $5,386 $4,701
NYSEG
Service cost $9,054 $8,434 $1,745 $1,616
Interest cost 34,435 33,928 9,413 9,413
Expected return on plan assets (61,908) (60,333) - -
Amortization of prior service cost 2,167 2,329 (3,065) (3,079)
Recognized net actuarial (gain) loss (6,144) (8,355) 2,227 1,885
Amortization of transition (asset) obligation (615) (3,619) 4,000 4,033
Net periodic benefit cost $(23,011) $(27,616) $14,320 $13,868
RG&E
Service cost $2,740 $3,143 $515 $584
Interest cost 14,902 16,172 3,027 3,124
Expected return on plan assets (24,592) (25,646) - -
Unrecognized transition obligation - - 1,059 1,242
Amortization of prior service cost 631 731 571 670
Recognized net actuarial (gain) loss (3,453) (4,124) (132) (138)
Net periodic benefit cost $(9,772) $(9,724) $5,040 $5,482
In April of 2004 Energy East contributed $19 million to its retirement benefit plans, including $11 million for CMP.
In December 2003 President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.
In May 2004 the FASB issued its FASB Staff Position (FSP) No. FAS 106-2, which addresses how and when a plan sponsor should account for the federal subsidy introduced by the Act and could require the plan sponsor to change previously reported information. FSP No. FAS 106-2 is effective for the first interim or annual period beginning after June 15, 2004. When FSP No. FAS 106-2 becomes effective it supersedes FSP No. FAS 106-1. The company, CMP, NYSEG and RG&E will apply FSP No. 106-2 beginning July 1, 2004. However, since detailed regulations necessary to implement the Act have not been issued, the companies are unable to conclude whether the benefits provided by their plans are actuarially equivalent to Medicare Part D under the Act. Any measures of the accumulated pension benefit obligation or net periodic postretirement benefit cost in the companies' financial statements or accompanying notes do not reflect any amount associated with the subsidy because the companies' are unable to conclude whether the benefits provided by their plans are actuarially equivalent to Medicare Part D. The companies have not yet determined the potential effects of the Act on their future postretirement costs, including the participation rates in their benefit plans, or whether any amendments to their benefit plans are appropriate given the provisions of the Act.
Note 10. Goodwill and Intangible Assets

~~The~~We ~~companies~~do nonot ~~longer~~ amortize goodwill ~~effective~~or ~~January 1, 2002, and do not amortize~~ intangible assets with indefinite lives (unamortized intangible assets). ~~RG&E~~We ~~has no goodwill or intangible assets with indefinite lives. The companies~~ test ~~both~~ goodwill and unamortized intangible assets for impairment at least annually. ~~The~~We ~~companies~~completed ~~amortize~~our ~~intangible~~annual ~~assets~~impairment ~~with~~testing ~~finite~~and ~~lives~~determined ~~(amortized~~that ~~intangible~~we ~~assets)~~had ~~and~~no ~~review~~impairment ~~them~~of ~~for~~goodwill ~~impairment.~~or ~~Annual~~unamortized ~~impairment~~intangible ~~testing~~assets ~~was~~at ~~completed~~September ~~and~~30, it2005. Energy ~~was~~East ~~determined~~and ~~that~~RG&E ~~there~~amortize ~~was~~intangible noassets ~~impairment~~with offinite ~~goodwill~~lives or(amortized ~~unamortized~~ intangible assets) ~~for~~and ~~the~~review ~~companies~~them atfor ~~September 30, 2003~~impairment.

~~Changes~~The ~~in the~~ carrying ~~amounts~~amount of ~~Energy~~our ~~East's~~ goodwill, bywas ~~operating~~the ~~segment,~~same ~~from~~at ~~January~~March 131, ~~2004~~2006, toand ~~June~~December 3031, ~~2004,~~2005. ~~are~~The ~~shown~~amounts inof ~~the~~goodwill ~~table~~by ~~below.~~operating segment (in thousands) are:

Electric Delivery	~~Electric~~Natural Gas Delivery	~~Natural Gas Delivery~~Other	~~Other~~Total	~~Total~~
(Thousands)
$844,491	$676,588	$4,274	$1,525,353
Balance, January 1, 2004	$844,531	$677,119	$11,473	$1,533,123
Goodwill related to businesses held for sale	-	-	(5,500)	(5,500)
Preacquisition income tax adjustment	(40)	(531)	117	(454)
Balance, June 30, 2004	$844,491	$676,588	$6,090	$1,527,169

~~The~~Our ~~carrying~~unamortized ~~amount~~intangible ~~of CMP's goodwill~~assets, which ishad ~~included~~a incarrying ~~its~~amount ~~electric~~of ~~delivery operating segment, was~~ $~~325~~19 million asat ofMarch ~~June 30~~31, ~~2004~~2006, and ~~January~~December 131, ~~2004~~2005, primarily consisted of pension assets. ~~The~~Our amortized intangible assets had a gross carrying amount of ~~NYSEG's~~$27 ~~goodwill~~million at March 31, ~~which~~2006, isand ~~included~~$31 million at inDecember ~~its~~31, ~~natural~~2005, ~~gas~~and ~~delivery~~primarily ~~operating~~consisted ~~segment,~~of investments in pipelines and water rights. Accumulated amortization was $1114 million asat ofMarch ~~June 30~~31, ~~2004~~2006, and ~~January~~$18 1,million ~~2004~~at December 31, 2005.

~~The~~RG&E ~~company's~~has ~~unamortized~~no ~~intangible~~goodwill ~~assets~~or ~~had~~unamortized aintangible ~~carrying amount of $10 million at June 30, 2004, and December 31, 2003, and primarily consisted of pension~~ assets. ~~The company~~RG&E's amortized intangible assets consisted of water rights and had a gross carrying amount of $313 million ~~at June 30, 2004,~~ and ~~December~~accumulated ~~31,~~amortization ~~2003, and primarily consisted~~ of ~~investments in pipelines. Accumulated amortization was~~ $132 million at ~~June~~March 3031, ~~2004~~2006, and ~~$12 million at~~ December 31, ~~2003. Estimated amortization expense for intangible assets for the next five years is approximately $3 million for 2004, $2 million for~~ 2005~~, and $1 million each year for 2006 through 2008~~.

CMP's unamortized intangible assets consist of pension assets and had a carrying amount of $2 million at June 30, 2004, and December 31, 2003. CMP's amortized intangible assets had a gross carrying amount and accumulated amortization of less than $0.3 million at June 30, 2004, and December 31, 2003, and primarily consisted of technology rights. Estimated amortization expense for intangible assets is $26 thousand for the years 2004 through 2006, and $8 thousand for 2007, after which amortization will be complete.
NYSEG's unamortized intangible assets had a carrying amount of $1.4 million at June 30, 2004, and December 31, 2003, and primarily consisted of pension assets, franchises and consents. NYSEG's amortized intangible assets had a gross carrying amount of $1.8 million at June 30, 2004, and $1.5 million at December 31, 2003, and accumulated amortization of $1 million at June 30, 2004, and December 31, 2003, and consisted of hydroelectric licenses. Estimated amortization expense for intangible assets for the next five years is $41 thousand for the years 2004 through 2006, $38 thousand for 2007 and $35 thousand for 2008.
RG&E's amortized intangible assets consist of water rights, and had a gross carrying amount of $3 million and accumulated amortization of $2 million at June 30, 2004, and December 31, 2003. Estimated amortization expense for intangible assets is $78 thousand for each of the next five years, 2004 through 2008.
Note 11. Segment Information

~~Energy~~Our ~~East's~~ electric delivery ~~business~~segment consists of ~~its~~our regulated transmission, distribution and generation operations in ~~Maine and~~ New York; and ~~its~~Maine, and our natural gas delivery ~~business~~segment consists of ~~its~~our regulated transportation, storage and distribution operations in New York, Connecticut, Maine, and Massachusetts. ~~and~~We ~~New~~measure ~~York~~segment profitability based on net income. Other includes: ~~the~~primarily ~~company's~~our ~~corporate~~energy ~~assets,~~marketing ~~interest income~~companies, ~~interest expense~~ and ~~operating~~interest ~~expenses;~~income, intersegment eliminations; and our other nonutility businesses.

~~CMP~~RG&E's electric delivery ~~business,~~segment ~~which~~consists itof ~~conducts~~its inregulated ~~Maine~~transmission, distribution and generation operations and its natural gas delivery segment consists of its regulated ~~transmission~~transportation, storage and distribution operations in New York. RG&E measures segment profitability based on net income.

~~NYSEG's~~Selected ~~electric~~information ~~delivery~~for ~~business~~Energy ~~consists~~East's ~~of its regulated transmission, distribution~~ and ~~generation operations. Its natural gas delivery business consists of its regulated transportation, storage and distribution operations. NYSEG operates in the State of New York. Other includes NYSEG~~RG&E's ~~corporate~~business ~~assets.~~segments is:

RG&E's electric delivery business consists of its regulated transmission, distribution and generation operations. Its natural gas delivery business consists of its regulated transportation, storage and distribution operations. RG&E operates in the State of New York. Other includes RG&E's corporate assets.

	Operating Revenues		Net Income
Three months ended March 31,	2006	2005	2006	2005

(Thousands)
Energy East
Electric Delivery	$785,306	$768,322	$58,749	$83,101
Natural Gas Delivery	756,899	721,197	72,728	70,303
Other	154,349	147,759	1,764	962

Total	$1,696,554	$1,637,278	$133,241	$154,366

RG&E
Electric Delivery	$185,638	$160,156	$24,695	$16,172
Natural Gas Delivery	160,873	155,564	15,590	14,756

Total	$346,511	$315,720	$40,285	$30,928

Selected information for Energy East's, CMP's, NYSEG's and RG&E's business segments is:
Electric Delivery Natural Gas Delivery Other Total
(Thousands)
Three Months Ended
June 30, 2004
Operating Revenues Energy East CMP NYSEG RG&E $641,057 $129,748 $358,521 $160,209 $240,282 - $69,974 $63,520 $99,227 - - - $980,566 $129,748 $428,495 $223,729
Net Income (Loss) Energy East CMP NYSEG RG&E $41,986 $3,430 $30,184 $27,464 $(12,431) - $712 $1,465 $8,511 - - - $38,066 $3,430 $30,896 $28,929
June 30, 2003
Operating Revenues Energy East CMP NYSEG RG&E $640,035 $135,259 $338,353 $166,384 $264,054 - $75,011 $62,228 $75,024 - - - $979,113 $135,259 $413,364 $228,612
Net Income (Loss) Energy East CMP NYSEG RG&E $29,900 $2,821 $28,130 $12,030 $(602) - $1,793 $2,643 $(1,581) - - - $27,717 $2,821 $29,923 $14,673
Electric Delivery Natural Gas Delivery Other Total
(Thousands)
Six Months Ended
June 30, 2004
Operating Revenues Energy East CMP NYSEG RG&E $1,371,652 $292,498 $762,505 $324,393 $922,006 - $258,204 $212,682 $267,981 - - - $2,561,639 $292,498 $1,020,709 $537,075
Net Income (Loss) Energy East CMP NYSEG RG&E $113,512 $24,257 $67,161 $41,143 $54,171 - $16,652 $13,726 $(9,065) - - - $158,618 $24,257 $83,813 $54,869
June 30, 2003
Operating Revenues Energy East CMP NYSEG RG&E $1,398,748 $311,676 $744,320 $342,678 $904,167 - $244,775 $212,628 $181,029 - - - $2,483,944 $311,676 $989,095 $555,306
Net Income (Loss) Energy East CMP NYSEG RG&E $92,575 $26,923 $67,722 $(2,319) $65,623 - $22,818 $18,482 $158,618 - - - $163,181 $26,923 $90,540 $16,163
Total Assets
June 30, 2004 Energy East CMP NYSEG RG&E $6,736,575 $1,788,504 $2,466,720 $1,923,840 $3,644,236 - $1,057,265 $568,339 $287,217 - - - $10,668,028 $1,788,504 $3,523,985 $2,492,179
December 31, 2003 Energy East CMP NYSEG RG&E $7,293,829 $1,806,853 $2,664,449 $2,288,175 $3,536,280 - $870,464 $590,555 $476,323 - $52,652 $82,100 $11,306,432 $1,806,853 $3,587,565 $2,960,830
Forward-looking Statements
This Form 10-Q contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements.
In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties and that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated industry; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of changing energy prices; the operation of the New York Independent System Operator and ISO New England, Inc.; the operation of a regional transmission organization; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements; the company's ability to expand its products and services, including its energy infrastructure in the Northeast; the company's ability to integrate the operations of Berkshire Energy Resources, CMP Group, Inc., Connecticut Energy Corporation, CTG Resources, Inc, RGS Energy Group, Inc., and NYSEG; the company's ability to achieve enterprise-wide integration synergies; market risk; the ability to obtain adequate and timely rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; and other considerations, such as the effect of the volatility in the equity markets on pension benefit cost, that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
(See report on Form 10-K for Energy East and RG&E for the fiscal year ended December 31, 2005, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

(See report on Form 10-K for Energy East, CMP, NYSEG and RG&E for fiscal year ended December 31, 2003, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)
Commodity Price Risk
: Commodity price risk, due to volatility experienced in the wholesale energy markets, is a significant issue for the electric and natural gas utility industries. We manage this risk through a combination of regulatory mechanisms, such as allowing for the pass-through of the market price of electricity and natural gas to customers, and through comprehensive risk management processes. These measures mitigate our commodity price exposure, but do not completely eliminate it.

NYSEG's and RG&E's current electric rate ~~plan~~plans ~~offers~~offer their retail customers choice in their electricity supply including afixed and variable rate ~~option,~~options and an option to purchase electricity supply from an ~~alternative~~ESCO. ~~energy~~Approximately ~~company~~45% of NYSEG's, and aapproximately ~~bundled rate option. Approximately 38~~78% of ~~NYSEG~~RG&E's, total electric load is now provided by an ~~alternative~~ESCO ~~energy company~~ or at the market price. NYSEG's and RG&E's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the ~~bundled~~fixed rate option, which combines delivery and supply service at a fixed price. ~~For~~NYSEG ~~2004~~and ~~the~~RG&E ~~customer~~use ~~supply cost component is based on average~~ electricity ~~forward~~contracts, ~~prices~~both ~~for~~physical ~~2003~~ and ~~2004 available during September 2002~~financial, ~~plus~~to ~~35%~~manage tofluctuations ~~cover~~in the ~~costs~~cost ~~and~~of ~~risk~~electricity ~~that NYSEG is assuming by providing a bundled rate option to retail customers. NYSEG actively hedges the load~~ required to serve customers who select the ~~bundled~~fixed rate option. AsWe ofinclude ~~July~~the ~~30,~~cost ~~2004,~~or ~~NYSEG's~~benefit ~~load~~of ~~was~~those ~~98%~~contracts ~~hedged~~in ~~for~~the ~~on-peak~~amount ~~periods~~expensed ~~and 92% hedged~~ for ~~off-peak~~electricity ~~periods~~purchased inwhen ~~2004. A fluctuation of $1.00 per megawatt-hour in~~ the ~~price~~related of electricity ~~would~~is ~~change earnings by $0~~sold.25 ~~million~~Owned ~~for~~electric ~~August~~generation ~~through~~and ~~December~~long-term ~~2004.~~supply ~~The~~contracts ~~percentage~~reduce of NYSEG's ~~hedged~~exposure, ~~load~~and issignificantly ~~based~~reduce ~~on NYSEG~~RG&E's ~~load forecasts~~exposure, ~~which~~to ~~include~~market ~~certain~~fluctuations ~~assumptions~~for ~~such~~procurement ~~as historical weather patterns. Actual results could differ as a result~~ of ~~changes~~their infixed ~~the~~rate ~~load~~option ~~compared~~electricity ~~to the load forecast~~supply.

~~Under~~As of April 2006 the ~~terms~~portion of ~~its~~load ~~Electric~~for ~~Rate~~fixed ~~Agreement~~rate ~~RG&E~~option iscustomers ~~allowed~~not tosupplied ~~recover~~by ~~its~~owned ~~actual~~generation ~~fuel~~or ~~expenses~~long-term ~~effective~~contracts ~~May~~is 1,100% ~~2004~~hedged for NYSEG, and ~~the~~100% ~~earnings~~hedged ~~risks~~for ~~related~~RG&E, tofor ~~changes~~on-peak inand ~~market~~off-peak ~~value~~periods offor ~~electricity~~May ~~are~~through ~~eliminated~~December 2006. ~~Beginning~~A ~~January~~fluctuation of $1,.00 ~~2005,~~per megawatt-hour in ~~accordance~~the ~~with~~average ~~its~~price ~~Electric~~of ~~Rate~~electricity ~~Agreement,~~would ~~RG&E~~change ~~will~~NYSEG's ~~offer~~earnings ~~its~~less ~~retail~~than ~~customers~~$150 ~~choice~~thousand, inand ~~their~~would ~~electricity~~change ~~supply~~RG&E's ~~including~~earnings aless ~~variable~~than ~~price~~$150 ~~option~~thousand, anfor ~~option~~May tothrough ~~purchase~~December ~~electricity~~2006. ~~supply~~The ~~from~~percentage anof ~~alternative~~hedged ~~energy~~load ~~company~~for NYSEG and ~~a fixed price option.~~ RG&E's ~~exposure~~is tobased ~~fluctuations~~on inload ~~the~~forecasts, ~~market~~which ~~price~~include ofcertain ~~electricity~~assumptions ~~will~~such beas ~~limited~~historical toweather ~~the~~patterns. ~~load~~Actual ~~required~~results tocould ~~serve~~differ ~~those~~as ~~customers~~a ~~who~~result ~~select~~of ~~the~~changes ~~fixed~~in ~~rate~~load ~~option,~~compared ~~which~~to ~~combines~~the ~~delivery~~load ~~and supply service at a bundled price~~forecast.

~~NYSEG~~Accumulated ~~and~~other ~~RG&E~~comprehensive ~~use~~income ~~natural~~associated ~~gas~~with ~~futures~~our ~~and~~financial ~~forwards~~electricity tocontracts ~~manage~~at ~~fluctuations~~March in31, ~~natural~~2006, ~~gas~~was ~~commodity~~$56 ~~prices~~million, ~~and~~reflecting ~~provide~~a ~~price~~decrease ~~stability~~of to$97 ~~customers~~million since December 31, 2005. The ~~cost~~decrease oris ~~benefit~~primarily a result of ~~natural~~wholesale ~~gas~~market ~~futures~~price ~~and~~changes ~~forwards~~for iselectricity. ~~included~~Other incomprehensive income for the ~~commodity~~remainder ~~cost~~of ~~when~~2006 ~~the~~will ~~related~~have ~~sales~~no ~~commitments~~effect ~~are~~on ~~fulfilled.~~future ~~NYSEG~~net ~~and~~income ~~RG&E~~because ~~are~~we ~~allowed~~only use financial electricity contracts to ~~pass~~hedge ~~all~~the ~~actual~~price ~~natural~~of ~~gas~~our ~~commodity~~electric ~~costs~~load ~~through~~requirements tofor customers who have chosen a fixed rate option.

~~Item~~Two 4of our energy marketing subsidiaries offer retail electric and natural gas service to customers in New York State and actively hedge the load required to serve customers that have chosen them as their commodity supplier. As of April 2006 the energy marketing subsidiaries' fixed price load is 99% hedged for electricity and 100% hedged for natural gas for May through December 2006. The percentage of hedged load for the energy marketing subsidiaries is based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in load compared to the load forecast.

~~The~~Item principal executive officers and principal financial officers of Energy East, CMP, NYSEG and RG&E evaluated the effectiveness of their respective company's disclosure controls and procedures as of the end of the period covered by this report4. Controls ~~"Disclosure controls~~ and procedures" are controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, within the time periods specified in the Securities and Exchange Commission's rules and forms, is recorded, processed, summarized and reported, and is accumulated and communicated to the company's management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that their respective company's disclosure controls and procedures are effective.Procedures

~~Energy~~The ~~East,~~principal ~~CMP,~~executive ~~NYSEG~~officers and ~~RG&E~~principal ~~each~~financial ~~maintain~~officers ~~a system~~ of ~~internal~~Energy ~~control~~East ~~over~~and ~~financial~~RG&E ~~reporting~~evaluated ~~designed~~the toeffectiveness ~~provide~~of ~~reasonable~~their ~~assurance~~respective tocompany's ~~its~~disclosure ~~management~~controls and ~~board~~procedures as of ~~directors regarding~~ the ~~preparation~~end of ~~reliable~~the ~~published~~period ~~financial~~covered ~~statements~~by ~~and~~this ~~the~~report. ~~safeguarding~~"Disclosure ofcontrols ~~assets~~and ~~against~~procedures" ~~loss~~are orcontrols ~~unauthorized~~and ~~use.~~other ~~Each~~procedures of a company's ~~system~~that ofare ~~internal~~designed ~~control~~to ~~over~~ensure ~~financial~~that ~~reporting~~information ~~contains~~required ~~self-monitoring~~to ~~mechanisms~~be ~~and~~disclosed ~~actions~~by ~~are~~the ~~taken~~company toin ~~correct~~the ~~deficiencies~~reports asthat ~~they~~it ~~are~~files ~~identified.~~or ~~There~~submits ~~were~~under nothe ~~changes~~Securities inExchange ~~the~~Act ~~companies'~~of ~~internal~~1934, ~~control~~within ~~over~~the ~~financial~~time ~~reporting~~periods ~~that~~specified ~~occurred~~in ~~during~~the ~~each~~SEC ~~company's~~rules ~~most~~and ~~recent~~forms, ~~fiscal~~is ~~quarter~~recorded, ~~that~~processed, ~~has~~summarized ~~materially~~and ~~affected~~reported, orand is ~~reasonably~~accumulated ~~likely~~and communicated to ~~materially affect,~~ the ~~respective~~ company's ~~internal~~management, ~~control~~including ~~over~~its ~~financial~~principal ~~reporting.~~executive Onofficer ~~January~~and 1,principal ~~2004~~financial officer, ~~Energy~~as ~~East~~appropriate, ~~commenced~~to ~~using~~allow atimely ~~new~~decisions ~~accounting~~regarding ~~system~~required todisclosure. ~~record~~Based ~~and~~on ~~report~~their ~~financial~~evaluation, ~~transactions.~~the ~~The~~principal ~~system~~executive ~~change~~officers ~~was~~and ~~undertaken~~principal tofinancial ~~standardize~~officers ~~accounting~~of ~~systems~~Energy East and toRG&E ~~consolidate~~concluded ~~the~~that ~~accounting~~their ~~functions~~respective ~~for Energy East~~company's ~~principal~~disclosure ~~operating~~controls ~~companies, including CMP, NYSEG~~ and ~~RG&E.~~procedures are effective.

Energy East and RG&E each maintain a system of internal control over financial reporting designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. On February 1, 2006, NYSEG modified certain internal controls over financial reporting to accommodate the implementation of its new customer care system. The customer care system is used for customer bill production and integrates NYSEG's revenue, accounts receivable and cash management transactions with Energy East's centralized accounting system. There was no other change in either company's internal control over financial reporting that occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, that company's internal control over financial reporting.

PART II - OTHER INFORMATION

Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds

(ac) ~~Changes~~Issuer inPurchases ~~Rights~~ of ~~Holders~~Equity ~~of Energy East Common Stock~~Securities

On June 18, 2004, the stockholders of the company approved amendments to the Certificate of Incorporation to eliminate the classification of the Board of Directors and to eliminate cumulative voting in the election of directors. On June 21, 2004, the company filed an Amendment to the Certificate of Incorporation to reflect the changes. All directors will be elected annually beginning at the 2005 Annual Meeting.

Energy East Corporation
Period	(a) Total number of shares purchased	(b) Average price paid per share	(c) Total number of shares purchased as part of publicly announced plans or programs	(d) Maximum number of shares that may yet be purchased under the plans or programs

Month #1 (January 1, 2006 to January 31, 2006)	30,960⁽¹⁾	$23.09	-	-

Month #2 (February 1, 2006 to February 28, 2006)	252,405⁽²⁾	$24.39	-	-

Month #3 (March 1, 2006 to March 31, 2006)	4,887⁽³⁾	$24.23	-	-

Total	288,252	$24.25	-	-

^{(e) Issuer Purchases of Equity Securities
Energy East Corporation
Period (a) Total number of shares purchased (b) Average price paid per share (c) Total number of shares purchased as part of publicly announced plans or programs (d) Maximum number of shares that may yet be purchased under the plans or programs
Month #1 (April 1, 2004 to April 30, 2004) 4,034(1) $24.30 - -
Month #2 (May 1, 2004 to May 31, 2004) 6,503(1) $22.60 - -
Month #3 (June 1, 2004 to June 30, 2004) 9,721(2) $23.54 - -
Total 20,258 $23.39 - -
(1)} Includes 9,136 shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan; and 21,824 shares of the company's common stock (Par Value $.01) that were withheld to satisfy tax withholding obligations upon vesting of shares of restricted stock awarded through the company's Restricted Stock Plan.⁽²⁾Includes 2,405 shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan; and 250,000 shares of the company's common stock (Par Value $.01) purchased for Treasury for issuance under the company's Restricted Stock Plan and Stock Option Plan.
⁽³⁾ Represents shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan.

Rochester Gas and Electric Corporation
Period	(a) Total number of shares purchased	(b) Average price paid per share	(c) Total number of shares purchased as part of publicly announced plans or programs	(d) Maximum number of shares that may yet be purchased under the plans or programs
Month #1 (April 1, 2004 to April 30, 2004)	None
Month #2 (May 1, 2004 to May 31, 2004)	470,000 (1)	$102.31	-	-
Month #3 (June 1, 2004 to June 30, 2004)	None
Total	470,000	$102.31	-	-

RG&E had no issuer purchases of equity securities during the quarter ended March 31, 2006.

(1)
CMP and NYSEG had no issuer purchases of equity securities during the quarter ended June 30, 2004.
Item 4.
Energy East Corporation
Energy East's Annual Meeting of Stockholders was held on June 18, 2004. The following matters were voted on:
(a)  The election of four directors:
Nominees Votes For Votes Withheld
Richard Aurelio 126,363,429 4,134,624
James A. Carrigg 126,050,963 4,447,090
David M. Jagger 125,642,840 4,855,213
Ben E. Lynch 125,253,822 5,244,231
(b)  Approval of an amendment to the Certificate of Incorporation to eliminate the classification of the Board of Directors:
Shares For: 123,959,588
Shares Against: 4,664,053
Shares Abstain: 1,874,412
(c)  Approval of an amendment to the Certificate of Incorporation to eliminate cumulative voting in the election of directors:
Shares For: 80,144,510
Shares Against: 26,967,131
Shares Abstain: 1,881,723
Broker Nonvoted: 21,504,689
(d) Approval of an existing employee stock purchase plan:
Shares For: 103,745,975
Shares Against: 3,712,018
Shares Abstain: 1,535,371
Broker Nonvoted: 21,504,689
(e) Ratification of the appointment of PricewaterhouseCoopers LLP as independent public accountants:
Shares For: 126,296,571
Shares Against: 3,107,602
Shares Abstain: 1,093,880
Central Maine Power Company
CMP's Annual Meeting of Stockholders was held on June 18, 2004. The election of three directors was voted on:
Nominees Votes For Votes Withheld
Sara J. Burns 3,121,680 -
Kenneth M. Jasinski 3,121,680 -
Wesley W. von Schack 3,121,680 -
New York State Electric & Gas Corporation
On June 18, 2004, RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation and the owner of all of the outstanding shares of NYSEG's common stock, by written consent in lieu of the annual meeting of stockholders, elected Kenneth M. Jasinski, James P. Laurito, Wesley W. von Schack and Denis Wickham directors of NYSEG. Mr. Wickham retired on July 1, 2004, in accordance with his previously announced plans.
Rochester Gas and Electric Corporation
On June 18, 2004, RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation and the owner of all of the outstanding shares of RG&E's common stock, by written consent in lieu of the annual meeting of stockholders, elected Kenneth M. Jasinski, James P. Laurito, Wesley W. von Schack and Denis Wickham directors of RG&E. Mr. Wickham retired on July 1, 2004, in accordance with his previously announced plans.
Item 6.
  Exhibits

~~(a) Exhibits -~~ See

Exhibit Index.

(b) The following reports on Form 8-K were filed or furnished during the quarter:
Energy East filed four reports on Form 8-K. One report, dated May 7, 2004, was furnished to report certain information under Item 7, "Financial Statements and Exhibits," Item 9, "Regulation FD Disclosure," and Item 12, " Results of Operation and Financial Condition," Two other reports, dated May 19, 2004, and May 24, 2004, were filed to report certain information under Item 5, "Other Events," and Item 7, "Financial Statements and Exhibits." Another report, dated June 10, 2004, was filed to report certain information under Item 5, "Other Events."
RG&E filed three reports on Form 8-K. Two reports, dated May 19, 2004, and May 24, 2004, were filed to report certain information under Item 5, "Other Events," and Item 7, "Financial Statements and Exhibits." Another report, dated June 10, 2004, was filed to report certain information under Item 5, "Other Events."
Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: August 5, 2004	ENERGY EAST CORPORATION (Registrant) By /s/Robert E. Rude Robert E. Rude Vice President and Controller (Principal Accounting Officer)
Date: May 5, 2006	ENERGY EAST CORPORATION (Registrant) By /s/Robert D. Kump Robert D. Kump Vice President, Controller & Chief Accounting Officer (Principal Accounting Officer)
Date: August 5, 2004	CENTRAL MAINE POWER COMPANY (Registrant) By /s/Robert S. Mahoney Robert S. Mahoney Vice President - Controller & Treasurer, Clerk (Principal Financial Officer)
Date: May 5, 2006	ROCHESTER GAS AND ELECTRIC CORPORATION (Registrant) By /s/Joseph J. Syta Joseph J. Syta Vice President - Controller and Treasurer (Principal Financial Officer)
Date: August 5, 2004	NEW YORK STATE ELECTRIC & GAS CORPORATION (Registrant) By /s/Joseph J. Syta Joseph J. Syta Vice President - Controller & Treasurer (Principal Financial Officer)
Date: August 5, 2004	ROCHESTER GAS AND ELECTRIC CORPORATION (Registrant) By /s/Joseph J. Syta Joseph J. Syta Vice President - Controller & Treasurer (Principal Financial Officer)

EXHIBIT INDEX

~~(a) (1)~~ The following exhibits are delivered with this report:

Registrant	Exhibit No.	Description of Exhibit
Energy East Corporation	3-5 -	~~Certificate~~By-Laws of ~~Amendment of~~ the ~~Certificate~~Company ofas ~~Incorporation~~amended ~~filed~~April ~~in the Office of the Secretary of State of the State of New York on June 21~~6, ~~2004~~2006.
	(A)10-21 -	Amended and Restated Employment Agreement dated as of July 1, 2004, by an among the Company, Energy East Management Corporation and W. W. von Schack.
	31-1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	(A)10-22 -	Supplemental Executive Retirement Plan Amendment No. 2.
	31-2	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	*32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
Rochester Gas and Electric Corporation	31-1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32* -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
	31-2	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
Central Maine Power	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	*32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Company	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32* -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
New York State Electric	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
& Gas Corporation	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32* -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Rochester Gas and	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
Electric Corporation	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32* -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

*Furnished pursuant to Regulation S-K Item 601(b)(32)._________________________________

~~(a)~~* Furnished ~~(2)~~pursuant ~~The~~to ~~following~~Regulation ~~exhibits~~S-K ~~are~~Item ~~incorporated herein by reference:~~601(b)(32).

Registrant	Exhibit No.	Filed in	As Exhibit No.
Energy East Corporation	3-1 -	Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on April 23, 1998 - Post-effective Amendment No.1 to Registration No. 033-54155	4-1
	3-2 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on April 26, 1999 - Company's 10-Q for the quarter ended March 31, 1999 - File No. 1-14766	3-3
Central Maine Power Company	(A)10-27 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766	10-22
New York State Electric & Gas Corporation	(A)10-34 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766	10-22

Registrant	Exhibit No.	Filed in	As Exhibit No.
Rochester Gas and Electric Corporation	(A)10-27 -	Energy East Corporation's Supplemental Executive Retirement Plan - Energy East Corporation's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766	10-33
	(A)10-28 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-5
	(A)10-29 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766	10-22

_________________________________ (A) Management contract or compensatory plan or arrangement.

Energy East agrees to furnish to the Commission, upon request, a copy of (i) the Five-Year Revolving Credit Agreement among Energy East, certain lenders, Wachovia Bank, National Association, as Administrative Agent, JP Morgan Chase Bank, as Syndication Agent and Citibank, N.A., KeyBank N.A. and UBS Loan Finance, LLC, as Co-Documentation Agents, dated as of July 21, 2004; and (ii) the Revolving Credit Agreement among NYSEG, RG&E, certain lenders, JP Morgan Chase Bank, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent and Citibank, N.A., KeyBank N.A. and UBS Loan Finance, LLC, as Co-Documentation Agents, dated as of July 21, 2004 (the "Joint Revolving Credit Agreement"). The total amount of securities under each such document does not exceed 10% of the total assets of Energy East.

NYSEG agrees to furnish to the Commission, upon request, a copy of the Joint Revolving Credit Agreement. The total amount of securities issuable by NYSEG under the Joint Revolving Credit Agreement does not exceed 10% of the total assets of NYSEG.

RG&E agrees to furnish to the Commission, upon request, a copy of the Joint Revolving Credit Agreement. The total amount of securities issuable by RG&E under the Joint Revolving Credit Agreement does not exceed 10% of the total assets of RG&E.

Item	TABLE OF CONTENTS - continued	Page
1	Notes to Condensed Financial Statements Forward-looking Statements	41 52
3	Quantitative and Qualitative Disclosures About Market Risk	53
4	Controls and Procedures	54
	PART II - OTHER INFORMATION
2	Changes in Securities, Use and Proceeds and Issuer Purchases of Equity Securities	54
4	Submission of Matters to a Vote of Security Holders	56
6	Exhibits and Reports on Form 8-K (a) Exhibits (b) Reports on Form 8-K	57
Signatures		58
Exhibit Index		59

Nominees	Votes For	Votes Withheld
Richard Aurelio	126,363,429	4,134,624
James A. Carrigg	126,050,963	4,447,090
David M. Jagger	125,642,840	4,855,213
Ben E. Lynch	125,253,822	5,244,231

Shares For:	123,959,588
Shares Against:	4,664,053
Shares Abstain:	1,874,412

Shares For:	80,144,510
Shares Against:	26,967,131
Shares Abstain:	1,881,723
Broker Nonvoted:	21,504,689

Shares For:	103,745,975
Shares Against:	3,712,018
Shares Abstain:	1,535,371
Broker Nonvoted:	21,504,689

Shares For:	126,296,571
Shares Against:	3,107,602
Shares Abstain:	1,093,880

Filing Compare · ROCHESTER GAS & ELECTRIC CORP