Energy East (EAS) 10-Q 2000 Q3 Quarterly report

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  September 30, 2000

OR

[  ]  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 1-14766

Energy East Corporation
(Exact name of registrant as specified in its charter)

New York (State or other jurisdiction of incorporation or organization)	14-1798693 (IRS Employer Identification No.)
P. O. Box 12904, Albany, New York (Address of principal executive offices)	12212-2904 (Zip Code)

(518) 434-3049
(Registrant's telephone number, including area code)

N/A
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the 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           

The number of shares of common stock (par value $.01 per share) outstanding as of October 31, 2000, was 118,026,998.

TABLE OF CONTENTS

PART I

		Page
Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and   Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	9 16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19

PART II

Item 1.	Legal Proceedings	20
Item 6.	Exhibits and Reports on Form 8-K (a) Exhibits (b) Reports on Form 8-K	20 20

Signature	21
Exhibit Index	22

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Energy East Corporation
Consolidated Statements of Income - (Unaudited)

	Three Months		Nine Months
Periods Ended September 30	2000	1999	2000	1999
	(Thousands, except per share amounts)
Operating Revenues
Sales and services	$651,146	$571,020	$1,907,491	$1,733,385
Operating Expenses
Electricity purchased and     fuel used in generation	281,263	283,883	730,392	692,304
Natural gas purchased	66,009	27,939	246,909	129,468
Other operating expenses	114,082	70,931	277,321	223,950
Maintenance	20,258	20,160	67,580	65,683
Depreciation and amortization	44,279	28,668	111,657	619,871
Other taxes	46,347	41,399	129,239	152,039
Gain on sale of generation assets	-	-	-	(674,572)
Writeoff of Nine Mile Point 2	-	-	-	72,532
Total Operating Expenses	572,238	472,980	1,563,098	1,281,275
Operating Income	78,908	98,040	344,393	452,110
Other (Income) and Deductions	(14,102)	(15,706)	(29,105)	(30,065)
Interest Charges, Net	39,156	37,397	96,732	102,298
Preferred Stock Dividends    of Subsidiary	287	493	485	2,214
Income Before Federal Income Taxes	53,567	75,856	276,281	377,663
Federal Income Taxes	20,218	28,975	93,134	188,251
Net Income	$33,349	$46,881	$183,147	$189,412
Earnings Per Share, basic and diluted	$.30	$.41	$1.62	$1.61
Dividends Paid Per Share	$.22	$.21	$.66	$.63
Average Common Shares Outstanding	112,812	114,204	112,995	117,890

The notes on pages 6 through 9 are an integral part of the financial statements.

Item 1.  Financial Statements (Cont'd)

Energy East Corporation
Consolidated Balance Sheets - (Unaudited)

	Sep. 30,   2000	Dec. 31,   1999
	(Thousands)
Assets
Current Assets
Cash and cash equivalents	$65,350	$116,806
Special deposits	1,876	1,232
Temporary investments	81,984	760,996
Accounts receivable, net	346,760	157,383
Fuel, at average cost	46,946	16,055
Materials and supplies, at average cost	54,509	8,124
Prepayments	70,596	34,377
Total Current Assets	668,021	1,094,973
Utility Plant, at Original Cost
Electric	4,786,045	3,393,135
Natural gas	1,640,960	616,380
Common	219,438	140,035
	6,646,443	4,149,550
Less accumulated depreciation	3,062,166	2,034,312
Net Utility Plant in Service	3,584,277	2,115,238
Construction work in progress	50,638	12,689
Total Utility Plant	3,634,915	2,127,927
Other Property and Investments, Net	364,673	112,324
Regulatory and Other Assets
Regulatory assets
Purchase power contracts	240,868	-
Unfunded future federal income taxes	168,819	27,655
Unamortized loss on debt reacquisitions	62,205	52,671
Demand-side management program costs	45,614	52,649
Environmental remediation costs	78,506	58,400
Other	185,940	19,612
Total regulatory assets	781,952	210,987
Other assets
Goodwill, net	921,187	21,547
Prepaid pension benefit	307,096	174,741
Other	157,864	26,898
Total other assets	1,386,147	223,186
Total Regulatory and Other Assets	2,168,099	434,173
Total Assets	$6,835,708	$3,769,397

The notes on pages 6 through 9 are an integral part of the financial statements.

Item 1.  Financial Statements (Cont'd)

Energy East Corporation
Consolidated Balance Sheets - (Unaudited)

	Sep. 30,   2000	Dec. 31,   1999
	(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$36,761	$2,606
Notes payable	303,819	163,240
Accounts payable and accrued liabilities	226,925	135,801
Interest accrued	39,723	16,535
Taxes accrued	-	14,732
Accumulated deferred federal income tax, net	67,268	48,607
Other	224,482	80,995
Total Current Liabilities	898,978	462,516
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	82,585	58,923
Deferred income taxes, unfunded future federal      income taxes	70,066	13,024
Gain on sale of generation assets	238,176	-
Other	143,962	20,817
Total regulatory liabilities	534,789	92,764
Other liabilities
Deferred income taxes	414,798	213,006
Purchase power contracts	240,868	-
Other postretirement benefits	259,353	161,370
Environmental remediation costs	92,240	78,400
Other	216,376	112,139
Total other liabilities	1,223,635	564,915
Total Regulatory and Other Liabilities	1,758,424	657,679
Long-term debt	2,404,104	1,235,089
Total Liabilities	5,061,506	2,355,284
Commitments	-	-
Preferred Stock of Subsidiary
Preferred stock redeemable solely at the option     of subsidiary	42,957	10,159
Preferred stock subject to mandatory redemption	1,210	-
Common Stock Equity
Common stock	1,198	1,108
Capital in excess of par value	885,302	660,936
Retained earnings	892,124	782,588
Accumulated other comprehensive income	(9,649)	(1,681)
Treasury stock, at cost	(38,940)	(38,997)
Total Common Stock Equity	1,730,035	1,403,954
Total Liabilities and Stockholders' Equity	$6,835,708	$3,769,397

The notes on pages 6 through 9 are an integral part of the financial statements.

Item 1.  Financial Statements (Cont'd)

Energy East Corporation
Consolidated Statements of Cash Flows - (Unaudited)

Nine Months Ended September 30	2000	1999
	(Thousands)
Operating Activities
Net income	$183,147	$189,412
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	111,657	619,871
Federal income taxes and investment tax      credits deferred, net	(6,334)	(440,208)
Gain on sale of generation assets	-	(674,572)
Writeoff of Nine Mile Point 2	-	72,532
Pension income	(49,233)	(60,736)
Changes in current operating assets and liabilities
Accounts receivable	84,984	26,735
Inventory	(26,577)	53,068
Prepayments	491	(60,145)
Accounts payable and accrued liabilities	(128,427)	(8,696)
Taxes accrued	4,335	183,552
Interest accrued	12,512	14,369
Other, net	(37,756)	76,441
Net Cash Provided by (Used in) Operating Activities	148,799	(8,377)
Investing Activities
Sale of generation assets	-	1,850,000
Acquisitions, net of cash acquired	(1,445,297)	-
Utility plant additions	(89,167)	(46,689)
Temporary investments, net	936,174	(995,182)
Other property and investments	14,690	(13,383)
Net Cash (Used in) Provided by Investing Activities	(583,600)	794,746
Financing Activities
Repurchase of common stock	(149,261)	(306,772)
Treasury stock acquired, net	-	(31,386)
Repayments of first mortgage bonds and preferred    stock of subsidiaries, including net premiums	(96,705)	(144,557)
Long-term notes, net	649,036	(27,272)
Notes payable, net	53,886	(78,300)
Dividends on common stock	(73,611)	(75,091)
Net Cash Provided by (Used in) Financing Activities	383,345	(663,378)
Net (Decrease) Increase in Cash and Cash Equivalents	(51,456)	122,991
Cash and Cash Equivalents, Beginning of Period	116,806	48,068
Cash and Cash Equivalents, End of Period	$65,350	$171,059
Supplemental Disclosure of Cash Flows Information
Cash paid during the period
Interest, net of amounts capitalized	$79,389	$78,066
Income taxes (1999 includes $400,537 related to gain     on sale of generation assets)	$97,161	$464,409

The notes on pages 6 through 9 are an integral part of the financial statements.

Item 1.  Financial Statements (Cont'd)

Energy East Corporation
Consolidated Statements of Retained Earnings - (Unaudited)

Nine Months Ended September 30	2000	1999
	(Thousands)
Balance, beginning of period	$782,588	$662,562
Add net income	183,147	189,412
Deduct dividends on common stock	73,611	75,091
Balance, end of period	$892,124	$776,883

Energy East Corporation
Consolidated Statements of Comprehensive Income - (Unaudited)

	Three Months		Nine Months
Periods Ended September 30	2000	1999	2000	1999
	(Thousands)
Net income	$33,349	$46,881	$183,147	$189,412
Other comprehensive income, net of tax
Foreign currency translation adjustment	7	1	(31)	(95)
Net unrealized (loss) on investments	(9,664)	(797)	(8,657)	(1,028)
Minimum pension liability adjustment	720	-	720	-
Total other comprehensive income (loss)	(8,937)	(796)	(7,968)	(1,123)
Comprehensive income	$24,412	$46,085	$175,179	$188,289

The notes on pages 6 through 9 are an integral part of the financial statements.

Item 1.  Financial Statements (Cont'd)

Note 1. Unaudited Consolidated Financial Statements

The accompanying unaudited consolidated financial statements reflect all adjustments which are necessary, in the opinion of management, for a fair presentation of Energy East Corporation's (company) consolidated results for the interim periods. All such adjustments are of a normal recurring nature. These unaudited financial statements consolidate the company's majority-owned subsidiaries after eliminating all intercompany transactions. Due to completion of its merger with Connecticut Energy Corporation (CNE) on February 8, 2000, and its mergers with CMP Group, Inc., CTG Resources, Inc. and Berkshire Energy Resources on September 1, 2000, the company's consolidated financial statements include CNE and its results beginning with February 2000, and include CMP Group, CTG Resources and Berkshire Energy and their results beginning with September 2000. The unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and notes contained in the company's annual report for the year ended December 31, 1999. Due to the seasonal nature of the company's operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Note 2. Acquisition of Connecticut Energy, CMP Group, CTG Resources and Berkshire Energy

The company has completed the four definitive merger agreements it entered into during 1999. Its merger with CNE was completed on February 8, 2000, and its mergers with CMP Group, CTG Resources and Berkshire Energy were completed on September 1, 2000. Each company is now a wholly-owned Energy East subsidiary. In connection with the mergers the company has registered as a holding company with the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935.

The four transactions were accounted for using the purchase method. In each transaction the purchase price was allocated to the assets acquired and liabilities assumed based on values on the date of purchase. The estimated cost in excess of the fair value of the net assets acquired in each transaction is reflected as goodwill on the balance sheet and will be amortized on a straight-line basis over four to 40 years. The amounts below may be adjusted over the twelve months following the mergers as the company continues to integrate operations and actual costs become known.

CMP Group: CMP Group is a holding company whose principal operating subsidiary, Central Maine Power Company (CMP), is primarily engaged in transmitting and distributing electricity generated by others to retail customers. The company acquired all of the common stock of CMP Group, 32.4 million shares, for $29.50 per share in cash. The purchase price was approximately $969 million, which included $12 million of merger-related costs. The company also assumed approximately $293 million of CMP Group preferred stock and long-term debt and a liability of approximately $61 million for costs associated with change in control provisions, employment agreements, a workforce management plan and a regulatory liability. The estimated goodwill is $318 million.

CTG Resources: CTG Resources is a holding company and the parent of Connecticut Natural Gas Corporation, a regulated natural gas distribution company. Under this merger agreement, 45% of the common stock of CTG Resources (3.9 million shares) was converted into 6.8 million shares of Energy East common stock, and 55% of the common stock of CTG Resources was exchanged for $193 million in cash, valued at $41.00 per CTG Resources share. The purchase price was approximately $358 million, which included approximately $7 million of merger-related costs. The company assumed approximately $220 million of CTG Resources' long-term debt and preferred stock and a liability of approximately $31 million for costs associated with change in control provisions, employment agreements and a workforce management plan. The estimated goodwill is $242 million.

Berkshire Energy: Berkshire Energy is a public utility holding company whose wholly-owned subsidiary, The Berkshire Gas Company, is a regulated local natural gas distribution company that operates in western Massachusetts. The company acquired all of the common stock of Berkshire Energy, 2.5 million shares, for $38.00 per share in cash. The purchase price was approximately $97 million, which included $1 million of merger-related costs. The company also assumed approximately $40 million of Berkshire Energy preferred stock and long-term debt and a liability of approximately $7 million for costs associated with change in control provisions, employment agreements and a workforce management plan. The estimated goodwill is $72 million.

Pro Forma Information: The following pro forma information for the company for the three months and nine months ended September 30, 2000 and 1999, which is based on unaudited data, gives effect to the company's four mergers as if they were completed January 1, 1999. This information does not reflect future revenues or cost savings that may result from the mergers and is not indicative of actual results of operations had the mergers occurred at the beginning of the periods presented or of results that may occur in the future.

	Three Months		Nine Months
Periods Ended September 30	2000	1999	2000	1999
	(Thousands, except per share amounts)
Revenues	$853,143	$889,990	$2,853,967	$2,893,499
Net income	$19,535	$29,968	$205,204	$202,560
Earnings per share of common stock	$.16	$.23	$1.69	$1.51

Pro forma adjustments reflected in the amounts presented above include: (1) adjusting the four merged companies' non-utility assets to fair value based on an independent appraisal, (2) amortization of goodwill, (3) elimination of merger costs (4) adjustments for estimated tax effects of the above adjustments (5) lower investment income due to the sale of temporary investments to complete the mergers and (6) interest expense due to the issuance of merger-related debt.

Note 3. Segment Information

Selected unaudited financial information for the company's business segments is presented in the following table. The company's "Energy Delivery - Electric" segment consists of its regulated electricity distribution, transmission and generation operations, and its "Energy Delivery - Natural Gas" segment consists of its regulated natural gas distribution, transportation and storage operations. "Other" includes the company's non-utility businesses, corporate assets and intersegment eliminations.

	Energy Delivery -      Electric	Energy Delivery -   Natural Gas	Other	Total
		(Thousands)
Three Months Ended
September 30, 2000
Operating Revenues	$519,866	$90,832	$40,448	$651,146
Net Income	$60,021	$(19,725)	$(6,947)	$33,349
September 30, 1999
Operating Revenues	$518,400	$40,660	$11,960	$571,020
Net Income (Loss)	$45,665	$(9,088)	$10,304	$46,881
Nine Months Ended
September 30, 2000
Operating Revenues	$1,390,501	$407,175	$109,815	$1,907,491
Net Income	$179,092	$6,010	$(1,955)	$183,147
September 30, 1999
Operating Revenues	$1,462,459	$231,386	$39,540	$1,733,385
Net Income (Loss)	$167,891	$16,614	$4,907	$189,412
Identifiable Assets
September 30, 2000	$4,052,090	$2,223,721	$559,897	$6,835,708
December 31, 1999	$2,303,466	$644,593	$821,338	$3,769,397

Note 4. Environmental Liability

(See the company's Form 10-K for the year ended December 31, 1999, Item 8. Financial statements and supplementary data, Note 9. Environmental Liability.)

With the completion of the company's merger transactions in September 2000, the company assumed an estimated liability of $2 million for remediation costs related to certain hazardous substances at eight sites, not including sites where gas was manufactured in the past, which are discussed below.

The company has a program to investigate and perform necessary remediation at its sites where gas was manufactured in the past. In connection with its merger transactions in February and September 2000, 11 sites where gas was manufactured in the past have been added to the company's 38 sites under investigation and remediation.

The estimate for all costs related to investigation and remediation of the 11 sites acquired in connection with the mergers is $12 million. This estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations.

The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites, reflected on the company's consolidated balance sheets was $89 million at September 30, 2000, and $77 million at December 31, 1999. The company recorded a corresponding regulatory asset, net of insurance recoveries, since it expects to continue to recover the net costs in rates.

Note 5. Reclassifications

Certain amounts have been reclassified on the unaudited consolidated financial statements to conform with the 2000 presentation.

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

(a) Liquidity and Capital Resources

Merger Agreements
(See the company's Form 10-Q for the quarter ended June 30, 2000, Item 2(a) Liquidity and Capital Resources, Merger Agreements, and the company's Form 8-K dated September 1, 2000.)

The company has completed the four definitive merger agreements it entered into during 1999. Its merger with CNE was completed on February 8, 2000, and its mergers with CMP Group, CTG Resources and Berkshire Energy were completed on September 1, 2000. (See Item 1, Notes 1 and 2 to the Consolidated Financial Statements.)

Energy Delivery - Electric Business

Nine Mile Point 2: (See the company's Form 10-Q for the quarter ended June 30, 2000, Item 2(a) Liquidity and Capital Resources, Nine Mile Point 2, and see the company's Form 8-K dated September 18, 2000.) New York State Electric & Gas Corporation (NYSEG) owns an 18% interest in the Nine Mile Point 2 nuclear generating station (NMP2). In 1999 the majority of NYSEG's investment in NMP2 was recovered through a gain on the sale of its coal-fired generating plants. The remaining balance was written off pursuant to Statement of Financial Accounting Standards No. 121. On May 31, 2000, NYSEG filed a petition with the New York State Public Service Commission (NYPSC) pursuant to its restructuring agreement requesting approval of auction protocols and regulatory treatment for the sale of NMP2.

On October 12, 2000, NYSEG received clarification of the NYPSC's position on their statewide initiative, which was announced earlier this year, and its implications for the sale of NMP2. Based on this clarification, NYSEG has decided to join the selling cotenants and auction its 18% interest in NMP2 pursuant to its restructuring agreement.

Central Maine Power Alternative Rate Plan: On September 18, 2000, the Maine Public Utilities Commission (MPUC) voted to approve CMP's Alternative Rate Plan (ARP 2000). ARP 2000 provides the vehicle for CMP and the company to share merger synergies with CMP's customers. Merger synergies have been estimated to be $25-$30 million per year.

ARP 2000 applies only to CMP's State jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission prices. Recovery of stranded costs, primarily over-market non-utility generator (NUG) contracts, has been provided for under Maine's Restructuring Law. Transmission prices are subject to regulation by the Federal Energy Regulatory Commission (FERC) and are expected to change each July. ARP 2000 begins January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007.

Price changes will be calculated by taking the prior year's inflation rate as determined by the gross domestic product (GDP) price index and subtracting a "productivity offset." The productivity offset for the years of the plan range between 2.0% in 2002 and 2.9% in 2007. The productivity offset for 2001 will be equal to the GDP price index. In addition, certain expiring amortizations will flow through to customers via the annual price adjustments.

Mandated costs outside of CMP's control that exceed $150,000 individually and exceed $3 million in aggregate in any calendar year will be recovered through the annual price adjustment. Mandated costs include nonrecurring events such as storms, floods and labor disturbances, and recurring costs that result from accounting, federal or state legislative, regulatory or tax changes.

CMP is required to meet certain standards of service quality and reliability. These standards include: 1) customer average interruption duration, 2) system average interruption, 3) MPUC complaint ratio, 4) percent of business calls answered, 5) percent of outage calls answered, 6) new service installation, 7) call center service quality, and 8) market responsiveness. Price changes could be reduced by as much as $3.6 million annually if all the standards are not met.

Beginning in July 2002, the price change will include 50% of any revenue deficiency should CMP's return on equity fall below 5.2% in the prior calendar year. There is no earnings cap during the term of ARP 2000, which will give CMP the opportunity to utilize synergies to offset goodwill amortization during the term of ARP 2000.

Electricity Transmission Rates: NYSEG is responsible for delivering wholesale customers' electricity on its transmission system. Rates charged for the use of NYSEG's transmission system are subject to FERC approval under FERC Order 888. NYSEG's transmission rate case was filed with the FERC in March 1997. Effective November 1997 NYSEG began charging its filed rate, which was accepted by the FERC subject to refund based on a FERC final order.

On August 17, 2000, the FERC issued an order in NYSEG's transmission rate case that effectively reduced NYSEG's filed rate retroactive to November 1997 and going forward. NYSEG has refunded $14 million to customers, which represents revenues collected subject to refund including interest. NYSEG's deferral of a portion of transmission revenues collected since November 1997 provided the majority of the amount refunded. On September 17, 2000, NYSEG filed a petition for rehearing with the FERC.

On September 28, 2000, the FERC approved new transmission rates for CMP, which became effective September 1, 2000.

Retail Access Credit: (See the company's Form 10-K for the year ended December 31, 1999, Item 7. Liquidity and Capital Resources, Electric Restructuring Plan.) On September 22, 2000, the NYPSC issued an order denying a petition NYSEG had filed in August 2000 related to issues concerning its retail access credit (the amount backed out of a customer's bill when that customer participates in retail access). NYPSC proceedings to review NYSEG's retail access credit are ongoing and issues being addressed include: development of a reasonable mechanism for evaluating if market prices exceed the level of the retail access credit; examination of whether the existing annual retail access credit, whether or not reshaped or restructured, should be increased or replaced with a market-based credit; and any cost of service or other issues that become relevant to resolving those two issues.

New York Independent System Operator: (See the company's Form 10-Q for the quarter ended June 30, 2000, Item 2(a) Liquidity and Capital Resources, New York Independent System Operator.) The New York Independent System Operator (NYISO) began operating on November 18, 1999. It administers a new, centralized energy and ancillary services market.

In April and May 2000 NYSEG petitioned the FERC to investigate and initiate emergency actions to correct start-up and transitional problems of the NYISO administered energy markets. On June 30, 2000, the NYISO filed a petition requesting a $1,300 bid cap in its administered energy markets. In response to NYSEG's petition concerning the energy markets and the NYISO's bid cap filing, on July 26, 2000, the FERC ordered a bid cap of $1,000 per megawatt-hour in the NYISO's energy markets until October 28, 2000, to give the NYISO time to correct transitional problems. The NYISO is planning to file with the FERC to extend the bid cap.

In early September, NYSEG filed a lawsuit in the New York State Supreme Court against the NYISO for $6.6 million claiming errors in its administration of the operating reserve market, including errors related to market flaws and determination of pricing that was not consistent with the provisions in the NYISO tariffs and contracts. The NYISO is seeking to transfer this action to the United States District Court for the Northern District of New York. NYSEG opposes the transfer on the ground that its complaint raises only state law claims. Pursuant to indemnification provisions of a contract with the NYISO, NYSEG intends to offset its full claim against other funds due the NYISO.

The company does not expect that the transitional problems in the NYISO energy and operating reserves markets will have a material adverse effect on its financial position or results of operations.

Non-utility Generation: NYSEG petitioned the FERC in 1995, asking for relief from having to pay approximately $2 billion more than its avoided costs for power purchased over the term of two NUG contracts. NYSEG's electric restructuring agreement provides for the recovery of those costs for the term of the contracts through a form of a non-bypassable wires charge. The FERC denied NYSEG's petition and its subsequent request for a rehearing. NYSEG believes that the overpayments under the two contracts violate the Public Utility Regulatory Policies Act of 1978.

NYSEG commenced an action in the United States District Court for the Northern District of New York in August 1997. The complaint asked the District Court to either reform the two NUG contracts by reducing the price NYSEG must pay for electricity under the contracts, or send the matter back to the FERC or to the NYPSC with direction that they modify such contracts. The complaint also sought repayment of all monies paid above NYSEG's avoided costs. On September 29, 2000, the District Court dismissed NYSEG's complaint and endorsed the FERC decision denying NYSEG's petition. NYSEG appealed the District Court's decision to the United States Court of Appeals (Second Circuit).

Energy Delivery - Natural Gas Business

Southern Connecticut Gas Performance-based Rate Plan: On October 6, 2000, the Connecticut Department of Public Utility Control (DPUC) issued a draft decision in the Southern Connecticut Gas Company's (SCG) rate proceeding designed to establish a multi-year performance-based rate (PBR) plan. The draft decision endorses the concept of PBR and recommends a four-year price freeze, the continuation of the gas adjustment and weather-normalization clauses, a 50/50 sharing between customers and shareholders of earnings in excess of the authorized 10.71% return on common equity, a pass through of gas supply savings using the gas adjustment clause, and service quality requirements to help ensure customer service standards are met.

The company and SCG filed written exceptions to the draft decision, specifically on the issues of the proper sharing of merger synergies and appropriate service quality standards. A final decision by the DPUC is expected in November 2000.

It is expected that the SCG decision will have a precedential effect on the PBR plan for Connecticut Natural Gas (CNG) which is currently in hearings. Synergies for the combined SCG and CNG have been estimated to average $15-$20 million on an annual basis for the next several years.

Connecticut Natural Gas Incentive Rate Plan: CNG proposed an Incentive Rate Plan (PBR) as a second phase of its rate case filed in November 1999. The PBR seeks the opportunity to share in returns on equity in excess of 11.8%, while holding rates constant for four years and passing back to firm sales customers all gas-related merger synergies. The IRP also includes certain performance and service measures that CNG must meet. A final decision on this phase of the rate case is expected later this year. This is a companion filing to the SCG PBR mentioned earlier.

Other Businesses

In light of its recent mergers, the company is in the process of examining all of its non-utility businesses to ensure they fit within its strategic focus. To date the company has exited two non-utility businesses, CNEX and TeleSmart. In addition, on September 29, 2000, the company completed the sale of an energy services company, XENERGY, Inc. to Kema USA Inc. The company incurred an accounting loss of approximately $4 million in the third quarter of 2000 as a result of the sale.

The company continues to provide a collection of various energy services through other subsidiaries, such as Union Water Power Company. Future non-utility businesses are expected to have more of an asset-based focus such as the company's investment in The Energy Network, whose primary business is the operation of a district heating and cooling system, and Cayuga Energy, which invests in peaking generation.

Other Matters

Statement 133: The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, in June 1998; No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133, in June 1999; and No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities - an amendment of FASB Statement No. 133, in June 2000. Statement 133 establishes standards for the accounting and reporting for derivative instruments and for hedging activities. Statement 133 requires that all derivatives be recognized as either assets or liabilities on a company's balance sheet at their fair value. Statement 137 delayed for one year the effective date for implementing Statement 133, to fiscal years beginning after June 15, 2000. Statement 138 provided guidance on how to interpret sections of Statement 133.

The company will adopt Statement 133 as of January 1, 2001. Substantially all of the company's derivative activity will receive hedge accounting treatment under Statement 133 with fair value adjustments recorded in Other Comprehensive Income. If Statement 133 were adopted on October 1, 2000, the estimated transition adjustment as of September 30, 2000, recorded in Other Comprehensive Income would be approximately $21 million and the effect on earnings would be a loss of less than $1 million. Based on the company's current risk management strategies, this adoption is not expected to have a material effect on its financial position or results of operations.

Investing and Financing Activities

Investing Activities: Capital spending for the first nine months of 2000 was $95 million including nuclear fuel but excluding the merger transactions with CNE, CMP Group, CTG Resources and Berkshire Energy. (See Item 1, Note 2 to the Consolidated Financial Statements, and Merger Agreements.) Capital spending for 2000, including nuclear fuel but excluding the four merger transactions, is projected to be $156 million and is expected to be paid for entirely 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.

Financing Activities: During the nine months ended September 30, 2000, the company repurchased 7.3 million shares of its common stock at an average price of approximately $20.50 per share. The company expects to repurchase approximately $150-200 million of its common stock on an annual basis.

The company has a revolving credit agreement with certain banks that provides for borrowing up to $300 million for a 364-day period, which the company expects to renew annually. The company had $175 million outstanding at September 30, 2000, under this agreement.

The company borrowed $500 million in connection with the CMP Group, CTG Resources and Berkshire Energy merger transactions. The associated interest rate, currently 7.02 %, is the 30-day London Interbank Offered Rate plus 40 basis points, and is reset monthly. The borrowing will be replaced by a long-term public offering of debentures in November 2000. The proceeds from the borrowing, along with proceeds from the sale of the company's generation assets, internally generated funds and a drawing on the $300 million revolving credit agreement were used to fund the cash portion of the consideration for the merger transactions. (See Item 3. Quantitative and Qualitative Disclosures About Market Risk, Interest Rate Risk.)

In January 2000 NYSEG redeemed $163 million of unsecured notes with cash and commercial paper.

CNE and SCG have credit lines with certain banks that renew annually and provide for borrowing up to $70 million. SCG has committed lines of $50 million until the end of June 2001, and CNE and SCG share a committed line of $20 million until December 29, 2000. Due to the company's acquisition of CNE, an additional short-term facility of $96 million was established to temporarily finance the redemption of long-term debt. That redemption was due to a provision in SCG's bond purchase agreements that gave the bondholders the right to have the bonds redeemed as a result of the acquisition. First mortgage bonds totaling $77 million were redeemed at a premium of $18 million.

SCG received approval from the DPUC to issue up to $200 million of secured medium-term notes. SCG issued $114 million of medium-term notes, which were used to repay the short-term debt incurred to redeem first mortgage bonds, and for other general corporate purposes.

CMP has a $75 million three-year secured revolving credit facility with three banks. In September 2000 $30 million of loans were issued under the facility, at an interest rate of 7.00%

Forward-looking Statements

This Form 10-Q contains certain forward-looking statements that are based on 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," "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 could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the deregulation and unbundling of energy services; the company's ability to compete in the rapidly changing and increasingly competitive electricity and natural gas utility markets; its ability to control non-utility generator and other costs; changes in fuel supply or cost and the success of its strategies to satisfy its electric and natural gas supply requirements; its ability to expand its products and services, including its energy infrastructure in the Northeast; its ability to integrate the operations of CNE, CMP Group, CTG Resources and Berkshire Energy with its operations; 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 it is doing business; weather variations affecting customer energy usage; and other considerations that may be disclosed from time to time in its publicly disseminated documents and filings. The company undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

(b) Results of Operations

Results for the three months and nine months ended September 30, 2000, include CMP Group, CTG Resources and Berkshire Energy effective September 1, 2000.

	Three Months Ended September 30,
	2000	1999	Change
	(Thousands, except per share amounts)
Operating Revenues	$651,146	$571,020	14%
Operating Income	$78,908	$98,040	(20%)
Net Income	$33,349	$46,881	(29%)
Average Common Shares Outstanding	112,812	114,204	(1%)
Earnings Per Share, basic and diluted	$.30	$.41	(27%)
Dividends Paid Per Share	$.22	$.21	5%

Excluding the sale of XENERGY, Inc. in September 2000, earnings per share for the quarter ended September 30, 2000, were 34 cents compared to 41 cents in 1999. The decrease was primarily due to lower investment income and higher costs of energy offset by higher retail electricity deliveries.

	Nine Months Ended September 30,
	2000	1999	Change
	(Thousands, except per share amounts)
Operating Revenues	$1,907,491	$1,733,385	10%
Operating Income	$344,393	$452,110	(24%)
Net Income	$183,147	$189,412	(3%)
Average Common Shares Outstanding	112,995	117,890	(4%)
Earnings Per Share, basic and diluted	$1.62	$1.61	1%
Dividends Paid Per Share	$.66	$.63	5%

Excluding the non-recurring benefits in 2000 and 1999 from the sale of the company's coal-fired plants, the NMP2 writeoff, and the sale of XENERGY, Inc., earnings per share for the nine months in 2000 were $1.59 compared to $1.49 in 1999. The increase was primarily due to cost control efforts, earnings from the merged companies, transmission revenues and fewer shares outstanding due to the share repurchase program. Those increases were partially offset by higher costs of energy, lower wholesale electricity deliveries as a result of the sale of the company's coal-fired plants last year, and lower retail electricity prices.

Operating Results for the Energy Delivery - Electric Business

	Three Months Ended September 30,
	2000	1999	Change
	(Thousands)
Retail Deliveries -      Megawatt-hours	4,322	3,512	23%
Operating Revenues	$519,866	$518,400	-
Operating Expenses	$402,804	$412,671	(2%)
Operating Income	$117,062	$105,729	11%

The $1 million increase in operating revenues is due to the addition of CMP's delivery revenues, and higher retail deliveries, substantially offset by lower wholesale activity and lower retail prices.

Operating expenses decreased $10 million primarily due to lower purchase costs of electricity related to lower wholesale activity, partially offset by the addition of CMP's purchases for retail deliveries and operating costs, and higher market prices of electricity supporting retail deliveries.

	Nine Months Ended September 30,
	2000	1999	Change
	(Thousands)
Retail Deliveries -      Megawatt-hours	11,144	10,391	7%
Operating Revenues	$1,390,501	$1,462,459	(5%)
Operating Expenses	$1,062,700	$1,043,372	2%
Operating Income	$327,801	$419,087	(22%)

The $72 million decrease in operating revenues is due to a decrease in wholesale deliveries as a result of the sale of the company's coal-fired generation plants last year and lower retail prices. Those decreases were partially offset by higher transmission revenues and the addition of CMP's electricity delivery revenues.

Operating expenses decreased $79 million, excluding a $98 million benefit in 1999 from the sale of the company's coal-fired generation assets net of the writeoff of NMP2. That decrease was primarily due to cost control efforts, a reduction in operating expenses because of the sale of the coal-fired generation plants and a related reduction in amortization of NMP2. Those decreases were partially offset by the addition of CMP's purchases for retail deliveries and operating costs, and higher purchase costs of electricity primarily due to higher market prices and higher than anticipated ancillary services costs associated with the NYISO.

Operating Results for the Energy Delivery - Natural Gas Business

	Three Months Ended September 30,
	2000	1999	Change
	(Thousands)
Retail Deliveries -      Dekatherms	12,660	7,056	79%
Operating Revenues	$90,832	$40,660	123%
Operating Expenses	$112,687	$49,398	128%
Operating Income	($21,855)	($8,748)	(150%)

The $50 million increase in operating revenues is due to the additional revenues from the three merged natural gas operating companies - SCG, CNG and Berkshire Gas.

Operating expenses increased $63 million primarily due to the additional natural gas purchases and operating costs associated with the three merged gas companies, and higher retail purchased gas costs caused by higher market prices.

	Nine Months Ended September 30,
	2000	1999	Change
	(Thousands)
Retail Deliveries -      Dekatherms	65,234	41,960	55%
Operating Revenues	$407,175	$231,386	76%
Operating Expenses	$368,264	$190,662	93%
Operating Income	$38,911	$40,724	(4%)

The $176 million increase in operating revenues is primarily due to the additional revenues from the three merged natural gas operating companies - SCG, CNG and Berkshire Gas - and the recovery of increased gas costs for non-residential deliveries.

Operating expenses increased $178 million primarily due to the additional natural gas purchases and operating costs associated with the three merged gas companies, and higher retail purchased gas costs caused by higher market prices.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

(See the company's Form 10-Q for the quarter ended June 30, 2000, Item 3. Quantitative and Qualitative Disclosures about Market Risk).

Interest Rate Risk: In June 1999 the company entered into a $500 million, one-year interest rate hedge on the benchmark 30-year Treasury Bond in anticipation of the expected issuance of long-term debt related to its mergers. In August 2000 the effect of this hedge with an associated interest rate of 6.31% was settled and rolled into a bridge financing when the forward yield on the 30-year Treasury Bond was 5.735%. The company plans to replace the bridge financing with a long-term public offering of debentures later this month. The effect of this market risk on results of operations is not material since the company plans to amortize the difference between 5.735%, the actual 30-year U.S. Treasury rate at August 31, 2000, and the interest rate of the long-term debt to be publicly offered later this year, over the life of the public offering.

Commodity Price Risk: Of the company's five operating utilities, only NYSEG is subject to the effect of market fluctuations in the price of natural gas and electricity purchased. CMP has no long-term supply responsibilities. It has secured standard offer power under a fixed price contract for commercial and industrial customers through March 1, 2001, but is permitted to recover any difference between the standard offer rate and its cost of procuring supply. CNG, SCG and Berkshire Gas all have gas adjustment clauses. NYSEG's natural gas exposure is limited to purchases for residential customers because it is allowed to pass through increases in the market price of natural gas to non-residential customers.

NYSEG uses natural gas futures and options contracts to manage its exposure to fluctuations in natural gas commodity prices. Such contracts allow NYSEG to fix margins on sales of natural gas. The cost or benefit of natural gas futures and options contracts is included in the commodity cost when the related sales commitments are fulfilled. As of September 30, 2000, the difference between cost and fair value of natural gas futures and options contracts outstanding is not material to the company's results of operations.

NYSEG has hedged its expected residential natural gas load for November and December 2000, and approximately 60% for calendar year 2001 through gas in storage and option contracts. For its unhedged positions in 2001, a $1.00 per dekatherm change in the cost of natural gas changes natural gas costs by $10 million. NYSEG is currently exploring available options to further hedge its natural gas purchases.

NYSEG uses electricity contracts to manage against fluctuations in the cost of electricity. These contracts allow NYSEG to fix margins on the majority of its retail electricity sales. The cost or benefit of electricity contracts is included in the amount expensed for electricity purchased when the electricity is sold. With the implementation of the NYISO, NYSEG began utilizing contracts for differences (CFDs), which are financial contracts with features similar to commodity swap agreements. The CFDs effectively fix the price NYSEG pays for certain power purchased from the NYISO. Using electricity contracts and CFDs, NYSEG has hedged approximately 90%-95% of its expected summer demand for 2001 and 2002 and approximately 90% of its total expected demand through March 2003, when a market-price pass through mechanism is expected to take effect pursuant to NYSEG's restructuring agreement.

PART II - OTHER INFORMATION

Item 1.  Legal Proceedings

(See the company's Form 10-Q for the quarter ended June 30, 2000, Part II - Other Information, Item 1(b) Legal Proceedings.) On October 30, 2000, NYSEG and Pennsylvania Electric Company (Penelec) received a letter from EME Homer City Generation, L.P. (EME), a subsidiary of the purchaser of the Homer City generating station (Station) in which NYSEG and Penelec each formerly owned a one-half interest. The letter gave NYSEG and Penelec notice that the U.S. Environmental Protection Agency has found alleged violations of the federal Clean Air Act related to the Station. EME has indicated that it will claim that certain fines, penalties, and costs arising out of or related to these alleged violations, which NYSEG believes may be material, are liabilities retained by NYSEG and Penelec under the terms of the asset purchase agreement for the Station. While it will continue to examine this matter, NYSEG believes that such fines, penalties and costs are not liabilities retained by NYSEG.

Item 6.  Exhibits and Reports on Form 8-K

(a)  Exhibits - See Exhibit Index.

(b)  Reports on Form 8-K

      Two reports on Form 8-K were filed. One, dated September 1, 2000, was filed to report certain information under Item 2, "Acquisition or Disposition of Assets." The other, dated September 18, 2000, was filed to report certain information under Item 5, "Other Events."

Signature

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

ENERGY EAST CORPORATION
                    (Registrant)

By  /s/ Wesley W. von Schack                                   

            Wesley W. von Schack
            Chairman and Chief Accounting Officer

Date:  November 8, 2000

EXHIBIT INDEX

The following exhibits are delivered with this report:

Exhibit No.
4-1 -	Indenture between the company and The Chase Manhattan Bank, as Trustee, dated as of August 31, 2000.
(A)10-38 -	Amended and Restated Director Share Plan.
(A)10-39 -	Deferred Compensation Plan - Director Share Plan.
(A)10-40 -	Deferred Compensation Plan for Directors.
(A)10-41 -	Employment Agreement dated as of June 14, 1999, for D. T. Flanagan.
27      -	Financial Data Schedule.

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

       The company agrees to furnish to the Commission, upon request, a copy of the First Supplemental Indenture between the company and The Chase Manhattan Bank, as Trustee, dated as of August 31, 2000. The total amount of securities authorized under such First Supplemental Indenture does not exceed 10% of the total assets of the company.