Energy East Corp - Quarterly Report (10-Q)

Table of Contents

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   June 30, 2008

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	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 (Incorporated in New York) 52 Farm View Drive New Gloucester, Maine 04260-5116 [phone] www.energyeast.com	14-1798693

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         

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer    X	Accelerated filer
Non-accelerated filer         (Do not check if a smaller reporting company)	Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes             No     X   

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

The number of shares of common stock (Par value $.01 per share) outstanding as of July 30, 2008, was 158,346,335.

 

 

	Table of Contents	Page
	Glossary	ii
	Forward-looking Statements	iv
	PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)    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    Notes to Condensed Consolidated Financial Statements	1 2 4 5 5 6
Item 2.	Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a) Liquidity and Capital Resources   (b) Results of Operations	17 22 24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	31
	PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 6.	Exhibits	32
Signatures		33
Exhibit Index		34

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. Berkshire Gas is a wholly-owned subsidiary of Berkshire Energy Resources. CMP Central Maine Power Company is a regulated utility primarily engaged in transmitting and distributing electricity generated by others to retail customers in Maine. CMP is a wholly-owned subsidiary of CMP Group, Inc. CNG Connecticut Natural Gas Corporation is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut. CNG is a wholly-owned subsidiary of CTG Resources, Inc. Energetix Energetix, Inc. markets electric and natural gas services in upstate New York. Energetix is a wholly-owned subsidiary of RGS Energy Group, Inc. 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, Inc. and Energy East Enterprises, Inc.

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. NYSEG is a wholly-owned subsidiary of RGS Energy Group, Inc. 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. RG&E is a wholly-owned subsidiary of RGS Energy Group, Inc. SCG The Southern Connecticut Gas Company is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut. SCG is a wholly-owned subsidiary of Connecticut Energy Corporation. SGF South Glens Falls Energy, LLC operated a natural gas fired generating unit in New York. SGF is 85% owned by Cayuga Energy, Inc. and 15% owned by GE Capital.

 

Abbreviations or acronyms frequently used in this report:

ALJ Administrative Law Judge AMI advanced metering infrastructure ARP 2000 Alternative Rate Plan 2000 DPS New York Department of Public Service DPUC Connecticut Department of Public Utility Control Dth dekatherm EITF 06-10 Emerging Issues Task Force Issue No. 06-10, "Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements" EPS earnings per share ESM earnings sharing mechanism FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FIN 48 FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 Iberdrola is one of the largest electric utilities and the largest renewable energy provider in the world. Its services reach over 22 million electric points of supply, with over ten million in Spain. Its operations include generation, transmission, and marketing of electricity and natural gas ISO-NE ISO New England Inc. kV kilovolts MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations Merger The proposed transaction whereby Energy East will merge with Green Acquisition Capital, Inc., a direct, wholly-owned subsidiary of Iberdrola, S.A., and we would become a subsidiary of Iberdrola as provided for in the Merger agreement MPUC Maine Public Utilities Commission MW, MWh megawatt, megawatt-hour

NBC nonbypassable wires charge NUG nonutility generator NYISO New York Independent System Operator NYPSC New York State Public Service Commission NYSERDA New York State Energy Research and Development Authority PCB polychlorinated biphenyl RTO Regional Transmission Organization Russell Station A coal-fired electric generation facility in Greece, New York SAR stock appreciation right SEC United States Securities and Exchange Commission Statement 141(R) Statement of Financial Accounting Standards No. 141 (revised 2007), Business Combinations Statement 157 Statement of Financial Accounting Standards No. 157, Fair Value Measurements Statement 159 Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment of FASB Statement No. 115 Statement 160 Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 Statement 161 Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 VEBA voluntary employees' beneficiary association

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, 2007, Item 1A - Risk Factors and Item 7A - MD&A - Quantitative and Qualitative Disclosures About Market Risk, and also include, among others:

• the occurrence of any event, change or other circumstances that could give rise to the termination of our Merger agreement with Iberdrola,
• the outcome of any legal or regulatory proceedings that have been instituted following the announcement of the Merger,
• our ability to compete in the rapidly changing and competitive electric and/or natural gas utility markets,
• increased state and FERC regulation,
• the operation of the NYISO and retroactive NYISO billing adjustments,
• the operation of ISO-NE as an RTO and CMP's continued participation in ISO-NE,
• 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 rising commodity costs on customer usage and uncollectible expense,
• market risk from changes in value of financial or commodity instruments, derivative or nonderivative, caused by fluctuations in interest rates or commodity prices,
• the ability of third parties to continue to supply electricity and natural gas,
• our ability to obtain adequate and timely rate relief and/or the continuation of current rate plans,
• the possible discontinuation or further modification of fixed-price supply programs in New York,
• environmental incidents,
• legal or administrative proceedings,
• changes in the cost or availability of capital,
• economic growth or contraction in the areas in which we do business,
• extreme weather-related events such as floods, hurricanes, ice storms or snow storms,
• weather variations affecting customer energy usage,
• changes in authoritative accounting guidance,
• acts of terrorism,
• the effect of volatility in the equity and fixed income markets on the cost of pension and other postretirement benefits,
• the effects of changes in the credit markets on our variable rate debt,
• 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
Periods ended June 30,	2008	2007	2008	2007
(Thousands, except per share amounts)
Operating Revenues
Utility	$957,915	$977,006	$2,469,578	$2,541,070
Other	124,361	112,020	279,348	261,693
Total Operating Revenues	1,082,276	1,089,026	2,748,926	2,802,763
Operating Expenses
Electricity purchased and fuel used in generation
Utility	317,416	351,412	656,310	736,685
Other	96,490	85,164	189,418	174,018
Natural gas purchased
Utility	195,634	174,232	742,517	712,738
Other	14,189	12,120	55,533	54,494
Other operating expenses	199,936	203,503	390,465	397,226
Maintenance	43,769	48,809	84,643	89,627
Depreciation and amortization	69,513	68,273	138,015	137,072
Other taxes	61,451	58,787	139,625	134,500
Total Operating Expenses	998,398	1,002,300	2,396,526	2,436,360
Operating Income	83,878	86,726	352,400	366,403
Other (Income)	(7,426)	(10,752)	(14,314)	(19,707)
Other Deductions	2,577	1,423	3,582	4,654
Interest Charges, Net	69,234	67,855	137,971	136,255
Preferred Stock Dividends of Subsidiaries	282	282	564	564
Income Before Income Taxes	19,211	27,918	224,597	244,637
Income Taxes	4,256	8,427	77,687	91,852
Net Income	$14,955	$19,491	$146,910	$152,785
Earnings per Share, basic	$.10	$.12	$.94	$1.00
Earnings per Share, diluted	$.09	$.12	$.93	$1.00
Dividends Declared per Share	$.31	$.30	$.62	$.60
Average Common Shares Outstanding, basic	157,016	157,112	157,053	152,341
Average Common Shares Outstanding, diluted	158,299	158,122	158,275	153,291
The notes on pages 6 through 16 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2008	Dec. 31, 2007
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$344,599	$97,066
Investments available for sale	-	177,045
Accounts receivable and unbilled revenues, net	836,017	990,255
Fuel and natural gas in storage, at average cost	262,583	258,172
Materials and supplies, at average cost	30,152	28,722
Deferred income taxes	-	38,383
Derivative assets	179,466	23,959
Prepayments and other current assets	71,367	132,991
Total Current Assets	1,724,184	1,746,593
Utility Plant, at Original Cost
Electric	5,848,077	5,787,362
Natural gas	2,749,899	2,708,612
Common	586,384	583,657
	9,184,360	9,079,631
Less accumulated depreciation	3,074,416	3,086,765
Net Utility Plant in Service	6,109,944	5,992,866
Construction work in progress	137,067	165,628
Total Utility Plant	6,247,011	6,158,494
Other Property and Investments	185,030	172,993
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	159,084	190,367
Deferred income taxes	66,940	-
Unfunded future income taxes	335,416	338,749
Environmental remediation costs	194,912	185,773
Unamortized loss on debt reacquisitions	50,134	48,819
Nonutility generator termination agreements	59,503	64,744
Hedging losses	-	11,154
Pension and other postretirement benefits	232,961	259,554
Other	314,686	346,079
Total regulatory assets	1,413,636	1,445,239
Other assets
Goodwill	1,526,048	1,526,048
Prepaid pension benefits	745,030	698,432
Derivative assets	21,161	17,450
Other	105,676	113,460
Total other assets	2,397,915	2,355,390
Total Regulatory and Other Assets	3,811,551	3,800,629
Total Assets	$11,967,776	$11,878,709
The notes on pages 6 through 16 are an integral part of our condensed consolidated financial statements.

 

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
		June 30, 2008		Dec. 31, 2007
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt		$133,948		$99,914
Notes payable		27,100		137,717
Accounts payable and accrued liabilities		448,373		484,963
Interest accrued		58,879		58,681
Taxes accrued		84,584		77,276
Derivative liabilities		315		11,491
Accumulated deferred income taxes		15,483		-
Other		264,322		251,239
Total Current Liabilities		1,033,004		1,121,281
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation		909,494		892,333
Deferred income taxes		-		5,088
Gain on sale of generation assets		84,085		99,514
Hedging gains		97,793		1,544
Pension benefits		122,197		124,300
Other		201,696		165,869
Total regulatory liabilities		1,415,265		1,288,648
Other liabilities
Deferred income taxes		1,406,323		1,322,738
Nuclear plant obligations		150,990		157,376
Pension and other postretirement benefits		385,934		451,642
Environmental remediation costs		147,108		158,629
Derivative liabilities		29,598		21,318
Other		254,092		248,368
Total other liabilities		2,374,045		2,360,071
Total Regulatory and Other Liabilities		3,789,310		3,648,719
Long-term debt		3,834,537		3,877,029
Total Liabilities		8,656,851		8,647,029
Commitments and Contingencies
Preferred Stock of Subsidiaries
Redeemable solely at the option of subsidiaries		24,587		24,587
Common Stock Equity
Common stock		1,583		1,583
Capital in excess of par value		1,750,730		1,752,465
Retained earnings		1,494,385		1,447,889
Accumulated other comprehensive income		41,661		7,609
Treasury stock, at cost		(2,021)		(2,453)
Total Common Stock Equity		3,286,338		3,207,093
Total Liabilities and Stockholders' Equity		$11,967,776		$11,878,709
The notes on pages 6 through 16 are an integral part of our condensed consolidated financial statements.

 

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Six months ended June 30,	2008	2007
(Thousands)
Operating Activities
Net income	$146,910	$152,785
Adjustments to reconcile net income to net cash  provided by operating activities
Depreciation and amortization	177,953	189,442
Deferred income taxes and investment tax credits, net	28,417	6,695
Pension income	(29,984)	(23,678)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	150,290	41,833
Inventory	(5,841)	68,952
Prepayments and other current assets	90,692	65,850
Accounts payable and accrued liabilities	(35,340)	(56,429)
Interest accrued	197	(2,380)
Taxes accrued	15,393	59,515
Customer refund	-	(10,047)
Other current liabilities	(18,698)	(53,081)
Pension and other postretirement benefits contributions	(53,000)	-
Changes in other assets	24,842	47,626
Changes in other liabilities
Asset sale gain account charges	(17,223)	(31,495)
Other	48,674	(10,563)
Net Cash Provided by Operating Activities	523,282	445,025
Investing Activities
Utility plant additions	(213,362)	(179,814)
Other property additions	(8,066)	(350)
Other property sold	-	19
Maturities of current investments available for sale	341,945	462,260
Purchases of current investments available for sale	(168,800)	(667,850)
Investments	(1,385)	3,519
Net Cash Used in Investing Activities	(49,668)	(382,216)
Financing Activities
Issuance of common stock	-	236,196
Repurchase of common stock	(7,151)	(8,339)
Long-term note repayments	(10,185)	(29,061)
Notes payable three months or less, net	(117,928)	(72,244)
Notes payable issuances	8,392	726
Notes payable repayments	(1,081)	(847)
Dividends on common stock	(98,128)	(82,186)
Net Cash (Used in) Provided by Financing Activities	(226,081)	44,245
Net Increase in Cash and Cash Equivalents	247,533	107,054
Cash and Cash Equivalents, Beginning of Period	97,066	93,373
Cash and Cash Equivalents, End of Period	$344,599	$200,427
The notes on pages 6 through 16 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Six months ended June 30,	2008	2007
(Thousands)
Balance, Beginning of Period	$1,447,889	$1,383,752
Adjustment to initially apply EITF 06-10	(2,286)	-
Add net income	146,910	152,785
	1,592,513	1,536,537
Deduct dividends on common stock	98,128	91,256
Balance, End of Period	$1,494,385	$1,445,281
The notes on pages 6 through 16 are an integral part of our condensed consolidated financial statements.

 

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30,	2008	2007	2008	2007
(Thousands)
Net income	$14,955	$19,491	$146,910	$152,785
Other comprehensive income, net of tax
Net unrealized (losses) gains on investments,     net of income tax benefit (expense) for the     three months of $216 in 2008 and $(114) in     2007 and for the six months of $685 in 2008     and $(172) in 2007	(327)	178	(1,036)	265
Amortization of pension costs for nonqualified     plans, net of income tax (expense) for the     three months of $(192) in 2008 and $(1,264)     in 2007 and for the six months of $(701) in     2008 and $(1,402) in 2007	1,412	1,859	1,705	2,068
Net unrealized gains (losses) on derivatives     qualified as hedges, net of income tax     (expense) benefit for the three months of     $(12,731) in 2008 and $(7,084) in 2007 and     for the six months of $(22,154) in 2008 and     $1,675 in 2007	19,272	10,636	33,731	(2,620)
Reclassification adjustment for derivative     losses (gains) included in net income,     net of income tax (benefit) expense for     the three months of $(688) in 2008 and     $(358) in 2007 and for the six months of     $205 in 2008 and $(26,288) in 2007	1,050	552	(309)	39,650
Net unrecognized (losses) gains on settled     cash flow treasury hedges, net of income     tax benefit (expense) for the three months     of $149 in 2008 and $(5,872) in 2007 and     for the six months of $(620) in 2008 and     $(5,872) in 2007	(200)	7,734	(39)	7,734
Net unrealized gains on derivatives qualified     as hedges	20,122	18,922	33,383	44,764
Total other comprehensive income	21,207	20,959	34,052	47,097
Comprehensive Income	$36,162	$40,450	$180,962	$199,882
The notes on pages 6 through 16 are an integral part of our condensed consolidated financial statements.

Notes to Condensed Consolidated Financial Statements

Note 1. Unaudited Condensed Consolidated Financial Statements

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

Our financial statements consolidate our majority-owned subsidiaries after eliminating all intercompany transactions.

On June 25, 2007, we announced that we had entered into a Merger agreement with Iberdrola, S.A., and Green Acquisition Capital, Inc. pursuant to which we will become a wholly-owned subsidiary of Iberdrola upon receipt of required regulatory approvals and satisfaction of other closing conditions.

Consummation of the Merger is subject to various customary closing conditions, including the absence of injunctions or restraints imposed by governmental entities, the receipt of required regulatory approvals and the absence of any event that would reasonably be expected to have a material adverse effect on Energy East. To date, all regulatory approvals have been received except approval from the NYPSC. Until the Merger is completed, Energy East will continue to operate as a separate company.

The accompanying unaudited financial statements should be read in conjunction with the financial statements and notes contained in the report on Form 10-K filed for the fiscal year ended December 31, 2007. Due to the seasonal nature of our operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

CMP Stipulation on ARP 2008 : As part of the stipulation establishing CMP's new five-year rate plan, ARP 2008, CMP was required to write off $5.2 million of previously deferred costs. This write-off was recognized in the second quarter of 2008.

Note 2. Other (Income) and Other Deductions

	Three Months		Six Months
Periods ended June 30,	2008	2007	2008	2007
(Thousands)
Interest and dividend income	$(3,691)	$(6,250)	$(7,230)	$(9,061)
Allowance for funds used during construction	(1,217)	(1,207)	(2,379)	(2,456)
Earnings from equity investments	(811)	(813)	(1,972)	(1,744)
Gains from energy risk contracts	(123)	(390)	(178)	(1,475)
Miscellaneous	(1,584)	(2,092)	(2,555)	(4,971)
Total other (income)	$(7,426)	$(10,752)	$(14,314)	$(19,707)
Losses on energy risk contracts	$458	$1,195	$859	$3,487
Civic donations	440	475	937	945
Gas cost incentive mechanism	443	-	451	-
Miscellaneous	1,236	(247)	1,335	222
Total other deductions	$2,577	$1,423	$3,582	$4,654

 

Note 3. Basic and Diluted Earnings per Share

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

	Three Months		Six Months
Periods ended June 30,	2008	2007	2008	2007
(Thousands)
Basic average common shares outstanding	157,016	157,112	157,053	152,341
Restricted stock awards	1,283	1,010	1,222	950
Potentially dilutive common shares	79	162	127	156
Options issued with SARs	(79)	(162)	(127)	(156)
Dilutive average common shares outstanding	158,299	158,122	158,275	153,291

We exclude from the determination of EPS options that have an exercise price that is greater than the average market price of the common shares during the period. Shares excluded from the EPS calculation for the three months ended June 30 were 2.8 million in 2008 and 2.1 million in 2007, and for the six months ended June 30 were 2.0 million in 2008 and 2.1 million in 2007.

Note 4. Income Taxes

Income taxes were $3.5 million less for the quarter ended June 30, 2008, and $2.8 million less for the quarter ended June 30, 2007, than they would have been at the statutory rate of 39.9%. The effective tax rate was 21.8% for the quarter ended June 30, 2008, and 29.9% for the quarter ended June 30, 2007. Income taxes were $12.1 million less for the six months ended June 30, 2008, and $5.9 million less for the six months ended June 30, 2007, than they would have been at the statutory rate. The effective tax rate was 34.5% for the six months ended June 30, 2008, and 37.5% for the six months ended June 30, 2007. Those rates are not necessarily indicative of what the effective rate will be in future years.

Differences between the statutory rate and the effective rate for the periods ended June 30, 2008 and 2007 were primarily due to:

	Three Months		Six Months
Periods ended June 30,	2008	2007	2008	2007
(Thousands)
Tax expense at statutory rate	$7,773	$11,245	$89,783	$97,774
Flow-through items
Medicare subsidy	(969)	(840)	(3,007)	(3,194)
Uncollectible accounts	(886)	231	264	2,882
Depreciation	916	592	110	2,607
Asset removal costs	(612)	(637)	(3,628)	(3,195)
Asset retirements	(928)	(466)	(3,008)	(2,418)
Investment tax credits	(398)	(325)	(1,819)	(1,977)
Other	(640)	(1,373)	(1,008)	(627)
Difference from statutory	(3,517)	(2,818)	(12,096)	(5,922)
Total income taxes	$4,256	$8,427	$77,687	$91,852

FIN 48: Gross unrecognized tax benefits as of December 31, 2007, were $23.5 million and include income taxes of $18.0 million, interest of $5.3 million and a penalty of $0.2 million. Gross unrecognized tax benefits as of June 30, 2008, were $22.3 million and include income taxes of $15.8 million, interest of $6.3 million and a penalty of $0.2 million. Including interest and penalty, $11.6 million of the gross unrecognized tax benefits would affect the effective tax rate, if recognized. The $2.2 million decrease in the gross income tax amount is primarily due to the unfavorable settlement of a state amended return refund claim.

We have been audited through 2000 for New York state income taxes and through 2001 for federal income taxes. The statute of limitations in Connecticut, Maine and Massachusetts has expired for all years through 2003. Our New York state returns for 2001 through 2004 and federal returns for 2002 through 2005 are currently under review. We anticipate that the reviews will be completed within the next 12 months. Approximately $11.6 million of our gross income tax reserves relate to the years currently under audit, with the majority relating to combined state reporting issues. We cannot predict the ultimate outcome of the reviews.

New York State Tax Legislation : On April 23, 2008, the state of New York enacted its 2008-2009 budget, which included an increase in the maximum capital-based tax from $1 million to $10 million effective January 1, 2008. We anticipate being taxed under the capital-based tax method in 2008, versus the income-based tax method and expect the legislation will increase our income tax expense by approximately $2.0 million.

Note 5. Variable Interest Entities

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.

We have power purchase contracts with NUGs. However, 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 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. Two of our NUG contracts expired in 2007. We are not able to determine if we have variable interests with respect to power purchase contracts with four remaining NUGs because we are unable to obtain the information necessary to: (1) determine if any of the four 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 four NUGs, and will continue to do so, but no NUG has yet provided the requested information. We did not consolidate any NUGs as of June 30, 2008, or December 31, 2007.

We continue to purchase electricity from the four NUGs at above-market prices. We are not exposed to any loss as a result of our involvement with the NUGs because we are allowed to recover through rates the cost of our purchases. Also, we are under no obligation to a NUG if it decides not to operate for any reason. The combined contractual capacity for the four NUGs is approximately 261 MWs. The combined purchases from the four remaining NUGs totaled approximately $135 million for the six months ended June 30, 2008, and $124 million for the six months ended June 30, 2007.

 

Note 6. Commitments and Contingencies

NYISO Billing 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.

SGF Bankruptcy Proceeding : In January 2008 the trustee in the SGF Chapter 7 bankruptcy proceeding brought adversarial proceedings seeking repayment of alleged preferential payments made in the one-year period preceding the bankruptcy filing to SGF affiliates in amounts totaling $14 million. We have evaluated the claims and filed responsive pleadings on April 1, 2008. We do not believe there is merit to the claims, but cannot predict the outcome of this matter.

Partial Acceptance Document in the Merger Proceeding : On March 14, 2008, the joint petitioners in the Merger proceeding - Iberdrola, Energy East, NYSEG and RG&E - filed a partial acceptance document in an effort to narrow the issues raised in the proceeding. The joint petitioners accepted certain ratepayer benefits and/or conditions that would be effective immediately upon closing of the Merger. The significant benefits and conditions included in the partial acceptance were:

• Divestiture of all of the New York fossil fuel generation that we own, including RG&E's Russell Station;
• Positive benefit adjustments of $201 million in the form of regulatory asset write-offs and increases in regulatory reserves, translating into approximately $55 million (4.4% on average) in immediate annual delivery rate reductions; and
• Iberdrola would support and encourage investments by Iberdrola Renewables (through its voting interest in Iberdrola Renewables) of $100 million in wind generation in the state of New York within the next three years subject to certain conditions.

DPS Staff Allegations Concerning Earnings Sharing Calculations : The DPS Staff in its testimony and briefs in the Merger proceeding has alleged that NYSEG did not properly compute the amount due to customers under the electric ESM in NYSEG's electric rate plan that was in effect from 2002 through 2006. The Staff claims that its preliminary analysis shows an additional $67 million, including interest, should have been allocated to customers. NYSEG vigorously disputes the Staff's claim. For each year 2002 through 2006 NYSEG made annual compliance filings, as required by the NYPSC. The DPS Staff has never formally presented its findings to NYSEG indicating its disagreements with NYSEG's 2002 through 2006 electric annual compliance filings. The DPS Staff stated in its direct testimony in the Merger proceeding that its audits have not been completed and the Staff will provide its response to NYSEG no later than NYSEG's next rate case. In its Briefs on Exceptions, filed on June 26, 2008, the Staff for the first time is now asking the NYPSC to decide the annual compliance filing issue in the Merger proceeding. The petitioners strongly opposed the Staff's approach and requested in their Briefs Opposing Exceptions, filed on July 3, 2008, that the NYPSC not decide this matter in the Merger proceeding and adhere to the original Staff testimony which stated that the Staff will present its findings no later than NYSEG's next rate case. NYSEG is unable to predict when or how the issue will be resolved. The Staff also raised issues in the Merger proceeding with regard to the ESM under the RG&E electric rate plan currently in effect, but has not

 

completed its analysis. RG&E believes that it has been properly calculating the amount due to customers in its annual compliance filings since 2004, but cannot predict how the matter will be resolved.

Alleged Overcharges by TEN Companies : The state of Connecticut (State) filed suit in February 2007 against Energy East and its subsidiaries TEN Companies, Inc., CNG and CTG Resources, Inc. for an alleged $14 million overcharge for heating and cooling services supplied to state buildings since 1992. Subsequently, the State provided an expert's report that claims the overcharges amounted to $30 million. In December 2007 the State filed a second action seeking injunctive relief to prevent TEN Companies from exercising its right to allow each of the various heating and cooling contracts to expire on their respective expiration dates and to require TEN Companies to continue to provide heating and cooling service under the contracts. In March 2008 the trial court denied that injunction. The State appealed the trial court's decision to the Connecticut Appellate Court and Connecticut Supreme Court and both appeals were summarily rejected. The Connecticut Legislature passed temporary legislation preventing TEN Companies from discontinuing service and was considering permanent legislation that would make TEN Companies a utility subject to regulation by the DPUC when the legislative session ended.

On May 7, 2008, TEN Companies and the State signed a memorandum of understanding (MOU) agreeing to stay the action through September 30, 2008, to allow the parties to finalize an agreement for the State's purchase of certain heating and cooling equipment that serves certain state buildings at a specified purchase price of $10.6 million, along with other terms specified in the MOU. On May 9, 2008, the parties jointly filed a motion to stay all pending litigation until September 30, 2008, which the court approved the same day. TEN Companies expects to finalize the agreement by the September 30, 2008 deadline, at which time all pending suits will be dismissed. We cannot predict the outcome of this proceeding, nor can we predict whether the Connecticut legislation will be reintroduced and enacted.

CNG Overearnings : In June 2008 CNG filed its monthly financial report showing that CNG exceeded its allowed return on equity by more than 100 basis points for the sixth consecutive 12-month period. As a result, the DPUC initiated an overearnings investigation. A statute allows the DPUC to adjust CNG's rates, on an interim basis, for the amount of excess revenues. An expedited hearing was conducted on July 7, 2008. On July 25, 2008, the DPUC issued a draft decision that would require CNG to reduce annual rates by $15.5 million. A final decision is expected on August 6, 2008.

SCG Overearnings : In July 2008 SCG filed its monthly financial report showing that it exceeded its allowed return on equity by more than 100 basis points for the sixth consecutive 12-month period. As a result, the DPUC initiated an overearnings investigation. A statute allows the DPUC to adjust SCG's rates, on an interim basis, for the amount of excess revenues. The DPUC has established a schedule to consider this issue with hearings on August 15, 2008, and a final decision on September 3, 2008. In its July 2008 monthly financial report filing SCG indicated that it will be filing a general rate case, with its letter of intent filing on August 1, 2008. SCG cannot predict the outcome of the overearnings investigation or its subsequent rate case.

Homer City : On June 23, 2008, NYSEG received a letter from subsidiaries of Edison Mission Energy regarding a notice of violation (NOV) from the United States Environmental Protection Agency (EPA) claiming that certain modifications to the Homer City Electric Generation Station (Homer City) during the time it was owned by NYSEG and Pennsylvania Electric Company were done in violation of EPA's new source review regulations. Homer City was sold in 1999 to Edison Mission Energy by NYSEG and Pennsylvania Electric Company. Edison Mission Energy asserts that it is entitled to indemnification for fines, penalties and certain costs arising out of the violations alleged in the NOV under the terms of the asset purchase agreement for Homer City. This appears to be the same claim that Edison Mission Energy made to NYSEG in October 2000. At that time NYSEG believed that it did not retain liability for these material claims. NYSEG continues to believe that the costs sought by Edison Mission Energy are not liabilities of NYSEG.

Note 7. New Accounting Standards

EITF 06-10 : Effective January 1, 2008, we began applying the consensus of EITF 06-10, which the FASB ratified in late March 2007. EITF 06-10 requires an employer to recognize a liability for a postretirement benefit related to a collateral assignment split-dollar life insurance arrangement. In a collateral assignment split-dollar life insurance arrangement, the employee, versus the employer, owns and controls the insurance policy. EITF 06-10 also requires an employer to recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement. Entities should recognize the effects of applying the consensus through either (1) a change in accounting principle through a cumulative-effect adjustment to retained earnings as of the beginning of the year of adoption or (2) a change in accounting principle through retrospective application to all prior periods. CNG is the only Energy East subsidiary with collateral assignment split-dollar life insurance arrangements. We elected to recognize the effects of applying the consensus as a change in accounting principle through a cumulative-effect adjustment that resulted in a decrease in retained earnings of $2.3 million. The application of EITF 06-10 did not affect results of operation or cash flows.

Statement 141(R) and Statement 160 : In December 2007 the FASB issued Statement 141(R) and Statement 160, both the result of a joint project between the FASB and the International Accounting Standards Board. The objective of Statement 141(R) is "to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports about a business combination and its effects." Some key changes that will result from the application of Statement 141(R) are: all transaction costs and most restructuring costs will be expensed, acquired in-process research and development costs will not be expensed at acquisition, and equity securities issued as part of the purchase price will be measured on the closing date instead of the announcement date. Statement 141(R) will apply to business combinations for which the acquisition date is on or after the beginning of an entity's first annual reporting period beginning on or after December 15, 2008 (our annual reporting period beginning January 1, 2009). It may not be applied before that date and must be applied prospectively.

Statement 160 is intended "to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements" about noncontrolling (sometimes called minority) interests. Minority interest earnings will no longer be excluded from net income as a result of applying Statement 160. Statement 160 is effective for fiscal years (including interim periods) beginning on or after December 15, 2008 (our fiscal year beginning January 1, 2009), with earlier adoption prohibited and prospective application required, except that the presentation and disclosure requirements are to be applied retrospectively. We expect that our application of both Statements will not affect our financial position, results of operation or cash flows.

Statement 161 : In March 2008 the FASB issued Statement 161, which requires enhanced disclosures about an entity's derivative instruments and hedging activities to enable investors to better understand their effects on the entity's financial position, financial performance and cash flows. It is intended to improve transparency about the location and amounts of derivative instruments in the financial statements and how the entity accounts for derivative instruments and related hedged items. Requirements include: disclosure of fair values of derivative instruments and their gains and losses in a tabular format, disclosure of derivative features that are credit risk-related, and cross-referencing within notes to enable financial statement users to locate important information about derivative instruments. Statement 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 (our fiscal year beginning January 1, 2009). Early application is encouraged. Disclosures for earlier periods presented for comparative purposes are encouraged but not required at initial adoption. In years after initial adoption, comparative disclosures are required only for periods subsequent to initial adoption. Our adoption of Statement 161 will not affect our financial position, results of operation or cash flows.

Note 8. Fair Value Measurements

In September 2006 the FASB issued Statement 157, which we adopted effective January 1, 2008, for financial assets and financial liabilities. Changes from current practice that result from the application of Statement 157 relate to the definition of fair value, the methods used to measure fair value and expanded disclosures about fair value measurements. Statement 157 applies under other accounting pronouncements that require or permit fair value measurements in which the FASB previously concluded that fair value is the relevant measurement attribute, but does not require any new fair value measurements. Our adoption of Statement 157 and related FASB Staff Positions (FSPs) had no effect on our financial position, results of operation or cash flows.

The FASB issued FSP FAS 157-2 in February 2008. FSP FAS 157-2 delays the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity's financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Nonfinancial assets and nonfinancial liabilities include all assets and liabilities other than those that meet the definition of a financial asset or financial liability as defined in paragraph 6 of Statement 159. FSP FAS 157-2 also requires additional disclosures concerning application of the provisions of Statement 157. FSP FAS 157-2 was effective upon issuance.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

		Fair Value Measurements at June 30, 2008, Using
Description	Total at June 30, 2008	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
(Thousands)
Assets
Noncurrent investments   available for sale - auction   rate securities	$3,900	-	-	$3,900
Noncurrent investments   available for sale - other	78,014	$78,014	-	-
Derivatives	200,627	90,540	-	110,087
Total	$282,541	$168,554	-	$113,987
Liabilities
Derivatives	$29,913	-	-	$29,913
Total	$29,913	-	-	$29,913

Valuation techniques : We value our noncurrent investments available for sale - auction rate securities at par due to the variable rate earned on the investments. Such securities ordinarily earn interest at rates established at periodic auctions, typically every seven or 35 days. However, periodic auctions for the securities began to fail during the first quarter of 2008 and we began earning formulaic failure rates on our investments. We held $3.9 million of those securities at June 30, 2008, which are earning pretax equivalent rates of 3.77%. At January 1, 2008, we included the fair value of those investments in Level 1. Due to uncertainties that began to develop in the auction rate securities markets and the need for management to use judgment to value the securities, we began to include the fair value measurements in Level 3 in the first quarter of 2008. In the first quarter of 2008 we classified the securities as current due to our expectation that they would be sold within twelve months. We began classifying our auction rate securities as noncurrent as of June 30, 2008.

We measure the fair value of our noncurrent investments available for sale - other using quoted market prices in active markets for identical assets and include the measurements in Level 1. The investments primarily consist of money market funds, but also include some fixed income and equity investments.

We determine the fair value of our various derivative assets and liabilities utilizing market approach valuation techniques:

• NYSEG, RG&E and our energy marketing subsidiaries enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. Those companies hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. Forward market price quotes for some NYISO locations are not actively traded and not readily available outright from market dealers. We derive forward market prices for some locations based on the historical relationship of prices in those locations to prices in locations where an active market exists. The resulting value represents the derived forward market price for each location, which we use to value the open derivative contracts. Because we adjust quoted market prices for our own load characteristics, we include these fair value measurements in Level 3.
• NYSEG, RG&E and our energy marketing subsidiaries enter into natural gas derivative contracts to hedge the forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value our open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange. Because we use prices quoted in an active market, we include these fair value measurements in Level 1.
• We enter into treasury-related derivative contracts to hedge the forecasted issuance of debt, to manage the risk of changes in interest rates associated with existing debt, and to maintain desired fixed-to-floating rate ratios. We value those derivatives based on indicative values provided by transaction counterparties and calculated based upon proprietary models that use well-recognized financial principles and reasonable, market-based estimates of relevant future market conditions. We assess the reasonableness of the transaction counterparty valuations utilizing a model that constructs forward LIBOR (London Interbank Offer Rate) rates from a spot LIBOR curve, applies the forward rates to construct pro forma cash flows and discounts the pro forma cash flows to the present using forward rates. Because the valuations provided by the counterparties are only indicative and do not represent prices at which the counterparties would be willing to transact, we include these fair value measurements in Level 3.

 

Instruments Measured at Fair Value on a Recurring Basis Using Significant
Unobservable Inputs

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Three months ended June 30, 2008	Auction Rate Securities	Derivatives, Net		Total
(Thousands)
Beginning balance	$19,925	$47,881		$67,806
Total gains (losses) (realized/unrealized)
Included in earnings	-	(9,447)		(9,447)
Included in other comprehensive income or    regulatory liabilities	-	41,740		41,740
Purchases, issuances and settlements	(16,025)	-		(16,025)
Transfers in and/or out of Level 3	-	-		-
Ending balance	$3,900	$80,174		$84,074
Total gains (losses) for the period included in earnings   attributable to the change in unrealized gains (losses)   relating to assets still held at June 30, 2008	-	$(335)		$(335)

 

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Six months ended June 30, 2008	Auction Rate Securities	Derivatives, Net		Total
(Thousands)
Beginning balance	-	$19,885		$19,885
Total gains (losses) (realized/unrealized)
Included in earnings	-	(14,888)		(14,888)
Included in other comprehensive income or    regulatory liabilities	-	73,900		73,900
Purchases, issuances and settlements	$(16,025)	1,277		(14,748)
Transfers in and/or out of Level 3	19,925	-		19,925
Ending balance	$3,900	$80,174		$84,074
Total gains (losses) for the period included in earnings   attributable to the change in unrealized gains (losses)   relating to assets still held at June 30, 2008	-	$(681)		$(681)

The amounts of realized and unrealized gains and losses included in earnings for the periods (above), which are reported in the various categories indicated are:

	Electricity purchased	Other operating expense	Other Income	Other Deductions	Interest Expense
(Thousands)
Total gains (losses) included in earnings for the periods ended June 30, 2008   Three months   Six months	$(8,728) $(13,386)	$(395) $(844)	$123 $178	$(458) $(859)	$11 $23
Change in unrealized gains (losses) relating to assets still held at June 30, 2008   Three months   Six months	-  -	-  -	$123 $178	$(458) $(859)	- -

 

Note 9. Long-term Debt

As of June 30, 2008, NYSEG and RG&E have outstanding $776 million of tax-exempt pollution control notes, of which $278 million have coupons fixed to maturity, $100 million are auction rate notes under a special rate period where the rate is fixed until January 2010, $296 million are 7-day auction rate notes and $102 million are 35-day auction rate notes.

In response to market disruptions triggered by downgrades of bond insurers that began in the first quarter of 2008, NYSEG and RG&E have restructured portions of their auction rate portfolios.

• In May 2008 NYSEG converted its $70 million NYSERDA Pollution Control Revenue Bonds, 2004 Series B maturing in December 2028 to a 5.35% fixed rate to maturity; the bonds become callable at par in May 2013. The coupon was subsequently swapped to a floating rate.
• In May 2008 RG&E converted its $50 million NYSERDA Pollution Control Revenue Bonds, 2004 Series B maturing in May 2032 to a 5.375% fixed rate to maturity; the bonds become callable at par in May 2013. The coupon was subsequently swapped to a floating rate.
• In July 2008 NYSEG converted three series of NYSERDA Pollution Control Refunding Revenue Bonds and one series of Indiana County Industrial Development Authority Pollution Control Revenue Refunding Bonds, totaling $187 million in principal amount, from 7-day auction rate mode to weekly variable rate demand notes (VRDNs). In connection with those conversions, certain banks have issued letters of credit to provide credit and liquidity enhancement for the VRDNs. The letters of credit are issued pursuant to a $190 million revolving credit agreement that expires in August 2009 among NYSEG, certain lenders and JPMorgan Chase Bank, N.A., as administrative agent.

As of July 24, 2008, NYSEG and RG&E were paying rates averaging 5.3% on the remaining $211 million of 7- and 35-day auction rate debt. NYSEG and RG&E are taking the steps necessary to place orders in the auctions for the remaining outstanding 7- and 35-day auction rate bonds in accordance with SEC guidance to issuers of auction rate debt.

Note 10. Accounts Receivable

Our accounts receivable include unbilled revenues of $154 million at June 30, 2008, and $273 million at December 31, 2007, and are shown net of an allowance for doubtful accounts of $57 million at June 30, 2008, and $51 million at December 31, 2007.

Note 11. Retirement Benefits

We have funded noncontributory defined benefit pension plans that cover substantially all of our employees. The plans provide defined benefits based on years of service and final average salary. We also have other postretirement health care benefit plans covering substantially all of our employees. The health care plans are contributory with participants' contributions adjusted annually.

 

Components of net periodic benefit (income) cost

	Pension Benefits		Postretirement Benefits
Three months ended June 30,	2008	2007	2008	2007
(Thousands)
Service cost	$8,140	$8,208	$1,303	$1,424
Interest cost	32,810	32,235	7,421	7,416
Expected return on plan assets	(60,876)	(58,196)	(2,081)	(776)
Amortization of prior service cost	1,081	1,166	(1,855)	(1,859)
Amortization of net loss	3,136	3,758	1,130	1,393
Amortization of transition obligation	-	-	1,700	1,700
Net periodic benefit (income) cost	$(15,709)	$(12,829)	$7,618	$9,298

 

	Pension Benefits		Postretirement Benefits
Six months ended June 30,	2008	2007	2008	2007
(Thousands)
Service cost	$16,741	$17,556	$2,745	$2,877
Interest cost	65,993	64,925	15,016	14,845
Expected return on plan assets	(121,640)	(116,430)	(4,151)	(1,423)
Amortization of prior service cost	2,150	2,307	(3,713)	(3,717)
Amortization of net loss	6,772	7,964	2,481	2,766
Amortization of transition obligation	-	-	3,400	3,400
Net periodic benefit (income) cost	$(29,984)	$(23,678)	$15,778	$18,748

Note 12. Segment Information

Our electric delivery segment consists of our regulated transmission, distribution and generation operations in New York and Maine, and our natural gas delivery segment consists of our regulated transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts. We measure segment profitability based on net income. Other includes primarily our energy marketing companies, and interest income, intersegment eliminations and our other nonutility businesses. Selected information for our business segments includes:

	Operating Revenues		Net Income
Three months ended June 30,	2008	2007	2008	2007
(Thousands)
Electric Delivery	$642,349	$682,602	$22,114	$21,001
Natural Gas Delivery	315,566	294,404	(3,914)	(1,412)
Other	124,361	112,020	(3,245)	(98)
Total	$1,082,276	$1,089,026	$14,955	$19,491

 

	Operating Revenues		Net Income
Six months ended June 30,	2008	2007	2008	2007
(Thousands)
Electric Delivery	$1,341,812	$1,449,284	$68,949	$76,155
Natural Gas Delivery	1,127,766	1,091,786	79,477	74,984
Other	279,348	261,693	(1,516)	1,646
Total	$2,748,926	$2,802,763	$146,910	$152,785

 

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

Overview

For a discussion of our Merger agreement with Iberdrola whereby we will become a wholly-owned subsidiary of Iberdrola upon completion of the Merger, see Recent Developments.

Energy East's primary operations, our electric and natural gas utility operations, are subject to rate regulation established predominantly by state utility commissions. The approved regulatory treatment on various matters significantly affects our results of operation, financial position and cash flows. We have rate plans for NYSEG's natural gas segment, RG&E's electric and natural gas segments, CMP and Berkshire Gas that currently allow for recovery of certain costs, including stranded costs, and provide stable rates for customers and revenue predictability. Where rate plans are not in effect, or as we approach the end of the term of existing plans, we monitor the adequacy of rate levels and file for new rates when necessary. NYSEG's current electric rates went into effect on January 1, 2007. CMP's rate plan expired at the end of 2007, and its new rate plan begins in 2009 and extends to 2013. NYSEG's natural gas rate plan and RG&E's electric and natural gas rate plans have terms that extend at least through the end of 2008. Under certain conditions those rate plans may continue.

Continuing uncertainty in the evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings that could significantly affect our operations and the rates that our customers pay for energy. Those proceedings, which are discussed below, could affect the nature of the electric and natural gas utility industries in New York and New England.

We expect to make significant capital investments to enhance the safety and reliability of our transmission and distribution systems and to meet the growing energy needs of our customers in an environmentally responsive manner. Capital spending is expected to exceed $4 billion through 2012, including $600 million in 2008. Major spending programs include the installation of AMI in New York and Maine requiring an investment of approximately $360 million; in excess of $1.5 billion of transmission investments, predominantly in Maine; a high efficiency transformer replacement program; and a "green" fleet initiative. The majority of our planned transmission investments will be pursuant to a regional reliability planning process. We estimate that about one-half of our capital spending program will be funded with internally-generated funds and the remainder through the issuance of a combination of debt and equity securities.

This MD&A for the quarter and six months ended June 30, 2008, should be read in conjunction with our MD&A, financial statements and related notes contained in our report on Form 10-K for the fiscal year ended December 31, 2007. Due to the seasonal nature of our operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Strategy

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 in an environmentally sensitive manner. Our operating companies have become increasingly efficient through realization of merger-enabled synergies. We intend to augment this strategic focus by addressing many of the precepts of the Energy Policy Act of 2005 including investing in: a) transmission to increase reliability, meet new load growth and

 

connect new, renewable generation to the grid; b) an AMI to promote customer conservation and peak load management; c) our distribution infrastructure to make it more reliable and efficient by reducing losses; and d) new regulated generation to the extent that it is approved by state legislators or regulators.

Our individual company rate plans are a critical component of our success. While specific provisions may vary among our public utility subsidiaries, our overall strategy includes creating stable rate environments that allow those subsidiaries to earn a fair return while minimizing price increases and sharing achieved savings with customers.

Recent Developments

On June 25, 2007, we announced that we had entered into a Merger agreement with Iberdrola and Green Acquisition Capital, Inc., a New York corporation that is a wholly-owned subsidiary of Iberdrola. On November 20, 2007, our shareholders approved the Merger agreement.

The Merger agreement provides for a business combination whereby we and our subsidiaries would become wholly-owned subsidiaries of Iberdrola and each outstanding share of Energy East common stock would be converted into the right to receive $28.50 per share in cash, without interest.

Iberdrola is one of the world's largest energy companies with more than 22 million electric points of supply and 26,000 employees. Iberdrola is a leading owner and operator of renewable energy facilities, having an installed capacity of over 7,000 MW of wind generation (the largest wind portfolio in the world) and almost 10,000 MW of hydroelectric generation. In the United States, Iberdrola jointly owns and operates the largest wind facility on the East Coast - Maple Ridge in upstate New York - and has over 21,000 MW in its renewable generation pipeline.

Consummation of the Merger is subject to satisfaction of various customary closing conditions, including the absence of injunctions or restraints imposed by government entities, the receipt of regulatory approvals and the absence of any event that would reasonably be expected to have a material adverse effect on Energy East. To date all regulatory approvals have been received except approval from the NYPSC. Until the Merger is completed, Energy East will continue to operate as a separate company.

On January 11, 2008, ten active parties, including the DPS Staff, filed testimony in the Merger approval proceeding in New York. The DPS Staff's testimony concluded that the Merger was not in the public interest and should be denied as filed. The joint petitioners - Iberdrola, Energy East, NYSEG and RG&E - filed rebuttal testimony on January 31, 2008, in response to the direct testimony of the staff and other parties.

Recommended Decision : On June 16, 2008, the ALJ assigned to the Merger approval proceeding in New York issued his nonbinding recommended decision. The ALJ recommended that the NYPSC disapprove the transaction on the ground that it does not satisfy the 'public interest' requirement. In the alternative, if the NYPSC should approve the transaction, the ALJ recommended several conditions that should be imposed including that:

• Iberdrola and its affiliates be prohibited from owning or operating electric generating plants (whether wind, fossil or hydropower) that are interconnected with the transmission or distribution systems of NYSEG or RG&E. The ALJ further recommended that Energy East, including NYSEG and RG&E, be required to divest all of its existing generation in New York.
• Iberdrola and its affiliates be subject to most of the financial and structural safeguards proposed by the DPS Staff and other parties in the proceeding, including credit quality protections, dividend limitations, ring fencing provisions, financial reporting requirements, affiliate transactions and substantive revisions to NYSEG's and RG&E's codes of conduct.
• NYSEG's and RG&E's customers be credited with "positive benefit adjustments" (PBAs) of $646 million, which includes the $201 million previously proposed by petitioners as part of their partial acceptance of some of the terms and conditions requested by DPS Staff and other parties (the $201 million would provide an immediate average delivery rate reduction of $55 million or 4.4%.)
• After the conclusion of this case, an 11-month general rate proceeding for NYSEG and RG&E be commenced to consider NYSEG's and RG&E's overall electric and natural gas revenue requirements and related matters, such as the implementation of the remaining $444 million of PBAs, retail access measures, and revenue decoupling mechanisms.

The NYPSC has not yet set a schedule for its consideration of the Merger. In light of such delay in this proceeding, on June 19, 2008, pursuant to the Merger agreement, we submitted to Iberdrola a notice extending the date by which the obligation to close the Merger ceases to be binding until December 25, 2008.

Briefs on Exceptions to the recommended decision were submitted by ten parties on June 26, 2008, and Briefs Opposing Exceptions were submitted on July 3, 2008, after which the matter was submitted to the NYPSC for its decision. We are unable to predict either the outcome of this proceeding or the timing of a NYPSC decision.

Electric Delivery Business Developments

DPS Staff Allegations Concerning Earnings Sharing Calculations : The DPS Staff in its testimony and briefs in the Merger proceeding has alleged that NYSEG did not properly compute the amount due to customers under the electric ESM in NYSEG's electric rate plan that was in effect from 2002 through 2006. The Staff claims that its preliminary analysis shows an additional $67 million, including interest, should have been allocated to customers. NYSEG vigorously disputes the Staff''s claim. For each year 2002 through 2006 NYSEG made annual compliance filings, as required by the NYPSC. The DPS Staff has never formally presented its findings to NYSEG indicating its disagreements with NYSEG's 2002 through 2006 electric annual compliance filings. The DPS Staff stated in its direct testimony in the Merger proceeding that its audits have not been completed and the Staff will provide its response to NYSEG no later than NYSEG's next rate case. In its Briefs on Exceptions, filed on June 26, 2008, the Staff for the first time is now asking the NYPSC to decide the annual compliance filing issue in the Merger proceeding. The petitioners strongly opposed the Staff's approach and requested in their Briefs Opposing Exceptions, filed on July 3, 2008, that the NYPSC not decide this matter in the Merger proceeding and adhere to the original Staff testimony which stated that the Staff will present its findings no later than NYSEG's next rate case. NYSEG is unable to predict when or how the issue will be resolved. The Staff also raised issues in the Merger proceeding with regard to the ESM under the RG&E electric rate plan currently in effect, but has not completed its analysis. RG&E believes that it has been properly calculating the amount due to customers in its annual compliance filings since 2004, but cannot predict how the matter will be resolved.

RG&E Transmission Project and Russell Station Shutdown : In December 2004 RG&E received approval from the NYPSC to upgrade its electric transmission system in order to provide sufficient transmission and ensure reliable service to customers in anticipation of the shutdown of the Russell Station. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, New York area. Construction on the project began in the first quarter of 2006 and was completed in May 2008. The cost of the project was approximately $125 million.

Russell Station was closed after completion of the transmission project. Severance and related costs associated with the shutdown are estimated at $7 million and are being accrued through July 31, 2008. These costs are being deferred and will be recovered as part of overall plant decommissioning costs. Iberdrola and Energy East committed to the NYPSC to seek to divest the Russell Station and the other Energy East fossil generating facilities in New York as a condition of the Merger. In the meantime, RG&E continues to prepare applications for regulatory approval to repower the Russell Station using natural gas.

CMP FERC Rate Update : CMP uses formula rates for transmission that are regulated by the FERC. The formula rates provide for the recovery of CMP's cost of owning, operating and maintaining local and regional transmission facilities and a local control center. On March 24, 2008, the FERC issued an order approving a base level return on equity of 11.1%, plus a 50 basis point adder for regional facilities and a 100 basis point incentive adder applicable to regional facilities placed in service after December 31, 2003, and before January 1, 2009, that have been approved as part of the ISO-NE regional planning process. In compliance with the FERC order, CMP has revised its prior transmission service billing to recover approximately $870,000 of additional revenue from transmission customers. Project owners seeking a transmission investment incentive for a project scheduled to be completed after December 31, 2008, are required to make a separate project-specific filing to the FERC, justifying the requested incentive in accordance with the FERC's stated criteria.

CMP's retail transmission prices increased by $28 million annually effective July 1, 2008, pursuant to FERC-approved formula rates for CMP and the New England RTO. That increase is primarily due to higher regional network service costs in New England, resulting from significant additions to pool transmission facilities, mainly in Connecticut and Vermont.

CMP Alternative Rate Plan 2008 : On May 1, 2007, CMP submitted a filing to the MPUC proposing a new alternative rate plan for a seven-year term beginning January 1, 2008 (referred to as ARP 2008). CMP's current ARP 2000 ended on December 31, 2007.

In June 2008 the MPUC approved a stipulation settling most of the issues in this proceeding. The stipulation provides for a $20 million distribution price decrease on July 1, 2008, and the implementation of a new five-year distribution rate plan beginning in January 2009 and continuing through December 2013. The stipulation retains the basic structure of ARP 2000, including annual price changes based on a specified inflation index less a 1% productivity offset, service quality indicators and associated penalties for failure to achieve the performance targets, and explicit provisions for the recovery of certain exogenous or mandated costs. The first price change under the ARP 2008 will occur on July 1, 2009. The stipulation provides for deferral accounting and recovery of extraordinary storm restoration costs and provides for reserve accounting to address recovery of costs associated with environmental clean-up costs for manufactured gas sites and PCB-contaminated facilities. CMP's proposed AMI project was not resolved and will be addressed in a second phase of the proceeding to be conducted later in 2008. ARP 2008 contains an ESM under which CMP can retain one-half of any annual distribution earnings in excess of 11%.

April 2007 Storms : CMP experienced two significant storms in April 2007 that resulted in extensive outages for its customers and significant damage to its distribution facilities. CMP incurred approximately $11 million in incremental costs to restore electric service to its customers after the storms. CMP estimated that it was entitled to recover approximately $4.6 million of those costs under ARP 2000 and deferred that amount as a regulatory asset. On March 17, 2008, CMP requested recovery of the deferred amount in its final compliance filing under ARP 2000. As part of the ARP 2008 stipulation described above, CMP agreed to recover only $0.5 million of the deferred regulatory asset. CMP expensed the $4.1 million difference in June 2008.

MPUC Inquiries into Continued Participation in New England RTO : Maine lawmakers have enacted legislation requiring the MPUC to undertake an inquiry concerning whether or not CMP and other Maine electric utilities should continue to participate in the New England RTO, as operated by the ISO-NE. The MPUC has issued various reports to the Maine Legislature concerning continued participation, including its final report on January 15, 2008. As a result of the inquiry, the MPUC concluded that there are serious and valid concerns with the status quo regulatory structure of transmission projects in Maine and New England. The MPUC developed and assessed three options: market reform, a Maine Independent transmission company and a Maine/New Brunswick market. The Maine Legislature considered the report during its 2008 session but deferred any action until the conclusion of further MPUC proceedings, as discussed below.

As part of a stipulation resolving the Merger approval in Maine, Iberdrola, Energy East and CMP agreed to take no action with regard to CMP's position in any RTO, including whether to extend, consent to, amend, or renew or otherwise modify the terms of CMP's contract with ISO-NE without explicit approval of the MPUC. The parties to the Merger proceeding in Maine and the MPUC agreed that CMP will initiate, and the MPUC will conduct, a proceeding to determine if extension or renewal of CMP's contract with ISO-NE is in the public interest. CMP submitted its initial filing in the proceeding on May 7, 2008, and made a subsequent filing on June 13, 2008. In accordance with the stipulation terms, the MPUC expects to issue a ruling in the proceeding in January 2009.

Any change in CMP's participation in the New England RTO could affect the process for siting and approval of new transmission investments and the cost recovery and rate of return for those investments.

CMP Power Reliability Programs: On July 1, 2008, CMP filed with the MPUC applications for certificates of public convenience and necessity for two significant transmission projects in Maine. The first project, called the Maine Power Reliability Program (MPRP), includes construction of approximately 350 miles of 345 kV and 115 kV transmission lines and the building or upgrading of several transmission substations. Costs for the MPRP are expected to total approximately $1.4 billion. CMP is requesting that the MPUC review and approve its application by June 2009 in order for construction to begin promptly and to allow completion of improvements by 2012, the identified year of need for reliability considerations.

The second application seeks certification of the Maine Power Connection (MPC), a joint project with Maine Public Service Company consisting of 200 miles of a new 345 kV electric transmission line as well as building or upgrading several substations. The MPC project costs are expected to total approximately $625 million. The line will enable the development of potential wind energy projects under consideration in northern Maine and provide, for the first time, a direct electrical connection between northern Maine and the southern Maine/New England bulk power grid. The MPC project will facilitate achievement of the goal, recently established by the Maine Legislature, of fostering the development of thousands of MWs of renewable wind energy within Maine, as well as address identified concerns with the lack of competition in the northern Maine electricity market.

 

Natural Gas Delivery Business Developments

CNG Billing Issue : In early February 2008 the DPUC opened an investigation regarding CNG's billing of certain customers during January 2008. Four of CNG's meter readers had intermittently and inappropriately approximated gas consumption for approximately 3,000 customers during November and December 2007. The approximations were half of the actual usage by the customers. This led to lower bills to the customers during November and December than actual usage would have produced. When actual readings were made in January 2008, the unbilled usage was included in customer's bills, resulting in higher bills than January usage would have produced. Connecticut's Attorney General has stated that CNG violated Connecticut law by erroneously billing customers in January 2008 for the full amount of the underbilling, $1.3 million, rather than prorating the amount over a number of months as Connecticut law requires. CNG believes that its practice is in accordance with Connecticut law but cannot predict the outcome of the proceeding.

CNG Overearnings : In June 2008 CNG filed its monthly financial report showing that CNG exceeded its allowed return on equity by more than 100 basis points for the sixth consecutive 12-month period. As a result, the DPUC initiated an overearnings investigation. A statute allows the DPUC to adjust CNG's rates, on an interim basis, for the amount of excess revenues. An expedited hearing was conducted on July 7, 2008. On July 25, 2008, the DPUC issued a draft decision that would require CNG to reduce annual rates by $15.5 million. A final decision is expected on August 6, 2008.

SCG Overearnings : In July 2008 SCG filed its monthly financial report showing that it exceeded its allowed return on equity by more than 100 basis points for the sixth consecutive 12-month period. As a result, the DPUC initiated an overearnings investigation. A statute allows the DPUC to adjust SCG's rates, on an interim basis, for the amount of excess revenues. The DPUC has established a schedule to consider this issue with hearings on August 15, 2008, and a final decision on September 3, 2008. In its July 2008 monthly financial report filing SCG indicated that it will be filing a general rate case, with its letter of intent filing on August 1, 2008. SCG cannot predict the outcome of the overearnings investigation or its subsequent rate case.

New Accounting Standards

See Item 1 - Note 7 to our Condensed Consolidated Financial Statements for explanations about the following new accounting standards from the FASB and when they will become effective:

• Statement 141(R) and Statement 160 issued in December 2007, and
• Statement 161 issued in March 2008.

(a) Liquidity and Capital Resources

Operating Activities : Significant operating activities that affected cash flows during the six months ended June 30, 2008, included the following:

• A decrease in accounts payable and accrued liabilities that decreased cash by $35 million,
• A decrease in receivables that increased cash by $150 million, and
• A decrease in prepayments and other current assets that increased cash $91 million.

In addition we made a $52 million cash contribution to NYSEG's VEBA, and a $1 million contribution to our pension plans.

Investing Activities : Utility capital spending for the six months ended June 30, 2008, was $213 million. We project utility capital spending of $600 million for 2008, about one-half of which is expected to be paid for with internally-generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates, and transmission investments.

Cash flows from investing activities include proceeds from the sale of auction rate securities, which were classified as current investments available for sale at December 31, 2007. We decreased our investments in auction rate securities by $173 million through the second quarter of 2008, in response to uncertainties in the auction rate securities markets. We replaced those investments with items classified as cash or cash equivalents. We began classifying our auction rate securities, which totaled $3.9 million, as noncurrent investments available for sale as of June 30, 2008. These investments are included in other property and investments.

Financing Activities : Our financing activities include those activities necessary for the company and its principal subsidiaries to maintain adequate liquidity and credit quality and ensure access to capital markets.

We repurchased 275,000 shares of our common stock in January 2008, primarily for grants of restricted stock. We awarded 334,505 shares of our common stock in February 2008, issued out of treasury stock, to certain employees through our Restricted Stock Plan, at a grant date fair value of $25.91 per share of common stock.

In response to market disruptions triggered by downgrades of bond insurers that began in the first quarter of 2008, NYSEG and RG&E have restructured portions of their auction rate portfolios.

• In May 2008 NYSEG converted its $70 million NYSERDA Pollution Control Revenue Bonds, 2004 Series B maturing in December 2028 to a 5.35% fixed rate to maturity; the bonds become callable at par in May 2013. The coupon was subsequently swapped to a floating rate.
• In May 2008 RG&E converted its $50 million NYSERDA Pollution Control Revenue Bonds, 2004 Series B maturing in May 2032 to a 5.375% fixed rate to maturity; the bonds become callable at par in May 2013. The coupon was subsequently swapped to a floating rate.
• In July 2008 NYSEG converted three series of NYSERDA Pollution Control Refunding Revenue Bonds and one series of Indiana County Industrial Development Authority Pollution Control Revenue Refunding Bonds, totaling $187 million in principal amount, from 7-day auction rate mode to weekly variable rate demand notes (VRDNs). In connection with those conversions, certain banks have issued letters of credit to provide credit and liquidity enhancement for the VRDNs. The letters of credit are issued pursuant to a $190 million revolving credit agreement that expires in August 2009 among NYSEG, certain lenders and JPMorgan Chase Bank, N.A., as administrative agent.

As of July 24, 2008, NYSEG and RG&E were paying rates averaging 5.3% on the remaining $211 million of 7- and 35-day auction rate debt. NYSEG and RG&E are taking the steps necessary to place orders in the auctions for the remaining outstanding 7- and 35-day auction rate bonds in accordance with SEC guidance to issuers of auction rate debt.

(b) Results of Operations

Earnings per Share

	Three Months		Six Months
Periods ended June 30,	2008	2007	2008	2007
(Thousands, except per share amounts)
Net Income	$14,955	$19,491	$146,910	$152,785
Earnings per Share, basic	$.10	$.12	$.94	$1.00
Earnings per Share, diluted	$.09	$.12	$.93	$1.00
Dividends Declared per Share	$.31	$.30	$.62	$.60
Average Common Shares Outstanding, basic	157,016	157,112	157,053	152,341
Average Common Shares Outstanding, diluted	158,299	158,122	158,275	153,291

Results for the quarter and six months ended June 30, 2008, included a charge of two cents per share resulting from provisions of the stipulation establishing CMP's new rate plan, ARP 2008. As part of this stipulation CMP was required to write off $5.2 million in previously deferred costs, including $4.1 million in deferred storm costs.

Three Months

Earnings per share, basic, for the second quarter of 2008 decreased 2 cents compared to the second quarter of 2007. The major decreases in EPS were:

• 2 cents due to lower electric margins, primarily related to lower deliveries, and
• 1 cent due to lower interest income.

Those decreases were partially offset by:

• Lower operating and maintenance costs in 2008 totaling 3 cents per share primarily due to higher merger-related costs and stock option expenses incurred in the second quarter of 2007.

Six Months

Earnings per share, basic for the six months ended June 30, 2008, decreased 6 cents per share as compared to the six months ended June 30, 2007, primarily because of:

• 10 cents due to lower electric margins, including 5 cents related to lower deliveries,
• 3 cents due to an increase in average common shares outstanding resulting from the issuance of 10 million shares in 2007, and
• 3 cents due to higher bad debt expense.

Those decreases were partially offset by:

• 4 cents due to a lower estimated annualized effective income tax rate for 2008,
• 4 cents due to lower operating and maintenance costs because of lower amortization of regulatory assets, and
• 2 cents due to lower stock option expense.

 

Energy Deliveries

Comparisons of energy deliveries and electricity commodity sales for the three months and six months ended June 30, 2008 and 2007, are shown below.

	Electricity Deliveries (MWh)				Natural Gas Deliveries (Dth)
Three months ended June 30,	2008	2007		Change	2008	2007		Change
(Thousands)
Residential	2,648	2,784		(5%)	9,901	11,493		(14%)
Commercial	2,351	2,470		(5%)	3,439	4,234		(19%)
Industrial	1,857	1,945		(5%)	486	539		(10%)
Other	564	545		3%	2,692	2,698		-
Transportation of customer-    owned natural gas	NA	NA		NA	16,927	16,885		-
Total Retail	7,420	7,744		(4%)	33,445	35,849		(7%)
Wholesale	1,005	1,783		(44%)	86	267		(68%)
Total Deliveries	8,425	9,527		(12%)	33,531	36,116		(7%)
Electricity commodity sales (1)	2,883	3,238		(11%)	NA	NA		NA
(1) Included in total deliveries

 

	Electricity Deliveries (MWh)				Natural Gas Deliveries (Dth)
Six months ended June 30,	2008	2007		Change	2008	2007		Change
(Thousands)
Residential	6,029	6,211		(3%)	46,231	50,182		(8%)
Commercial	4,787	4,931		(3%)	15,358	16,648		(8%)
Industrial	3,578	3,539		1%	1,982	2,078		(5%)
Other	1,180	1,142		3%	6,778	7,093		(4%)
Transportation of customer-    owned natural gas	NA	NA		NA	45,011	43,367		4%
Total Retail	15,574	15,823		(2%)	115,360	119,368		(3%)
Wholesale	2,315	3,720		(38%)	642	618		4%
Total Deliveries	17,889	19,543		(8%)	116,002	119,986		(3%)
Electricity commodity sales (1)	6,174	6,690		(8%)	NA	NA		NA
(1) Included in total deliveries

Several factors influence the volume of energy deliveries, but the major factor is weather. The effects of warmer or colder winter weather are especially significant to the demand for natural gas by our residential and commercial customers. Comparative weather data is shown in the following table.

Weather Conditions

Based on the number of heating degree days, weather for the second quarter of 2008 was significantly warmer than both 2007 and normal. Temperatures during the first half of 2008 were slightly warmer than in 2007 and normal.

	Three Months			Six Months
Periods ended June 30,	2008	2007	Normal	2008	2007	Normal
New York
Total heating degree days	806	910	957	4,093	4,257	4,368
(Warmer) Colder than prior year	(11%)	8%		(4%)	11%
(Warmer) than normal	(16%)	(5%)		(6%)	(3%)
New England
Total heating degree days	731	824	835	3,764	4,004	4,010
(Warmer) Colder than prior year	(11%)	13%		(6%)	13%
(Warmer) than normal	(12%)	(1%)		(6%)	-

Operating Results for the Electric Delivery Business

	Three Months		Six Months
Periods ended June 30,	2008	2007	2008	2007
(Thousands)
Operating revenues
Retail	$525,386	$524,567	$1,068,219	$1,117,235
Wholesale	74,436	104,574	172,283	232,050
Other	42,527	53,461	101,310	99,999
Total Operating Revenues	$642,349	$682,602	$1,341,812	$1,449,284
Operating Expenses
Electricity purchased and fuel used in generation	$317,416	$351,412	$656,310	$736,685
Other operating and maintenance expenses	167,445	175,794	327,157	343,066
Depreciation and amortization	44,988	44,590	89,732	89,113
Other taxes	38,661	36,818	80,577	75,248
Total Operating Expenses	$568,510	$608,614	$1,153,776	$1,244,112
Operating Income	$73,839	$73,988	$188,036	$205,172

Three Months

Operating Revenues : The $40 million decrease in operating revenues for the second quarter of 2008, was primarily the result of:

• A decrease of $30 million in wholesale revenues, reflecting a 44% decrease in wholesale volume,
• A decrease of $31 million resulting from lower accruals for recovery of NBC and stranded costs,
• A decrease of $21 million resulting from an 11% decline in sales volume under commodity supply service programs in New York,
• A decrease of $8 million resulting from a 4% decline in electric deliveries, and
• A decrease of $7 million in other revenue.

Those decreases were partially offset by:

• An increase of $28 million resulting from an increase in commodity prices under NYSEG's and RG&E's commodity supply service programs in New York,
• An increase of $17 million resulting from sales of transmission congestion contracts. The benefit of those sales is offset by lower NBC accruals,
• An increase of $10 million resulting from lower earnings sharing accruals, which are included in other revenues, and
• An increase of $2 million as a result of higher average delivery prices.

Operating Expenses : The $40 million decrease in operating expenses for the second quarter of 2008 was primarily the result of:

• A decrease of $34 million due to lower electricity purchased, primarily as a result of lower wholesale and commodity sales, and
• A decrease of $6 million in operating and maintenance costs because of lower amortization of regulatory assets.

Six Months

Operating Revenues : The $107 million decrease in operating revenues for the six months ended June 30, 2008, was primarily the result of:

• A decrease of $60 million in wholesale revenues, reflecting a 38% decrease in wholesale volume,

• A decrease of $31 million in average delivery prices, primarily resulting from lower transition charges. Transition charges allow our electric utility companies to recover actual generation and purchased power costs and have no net effect on earnings,

• A decrease of $30 million resulting from an 8% decrease in volume supplied under NYSEG's and RG&E's commodity supply programs,
• A decrease of $28 million resulting from higher accruals for recovery of NBC and stranded costs,
• A decrease of $12 million resulting from a 2% decrease in retail deliveries, and
• A decrease of $8 million in other revenues.

Those decreases were partially offset by:

• An increase of $24 million resulting from higher prices for electricity sales under supply service programs in New York,

• An increase of $23 million resulting from sale of transmission congestion contracts, and

• An increase of $15 million resulting from lower earnings sharing accruals, which are included in other revenues.

Operating Expenses : The $90 million decrease in operating expenses for the six months ended June 30, 2008, was primarily the result of:

• A decrease of $80 million in purchased power costs reflecting lower wholesale and commodity sales,
• A decrease of $11 million in regulatory amortization included in operating and maintenance costs, and
• A decrease of $7 million in various operating and maintenance expense items.

Those decreases were partially offset by:

• An increase of $3 million in bad debt accruals, and
• An increase of $5 million in other taxes, primarily for gross receipts taxes.

Operating Results for the Natural Gas Delivery Business

	Three Months		Six Months
Periods ended June 30,	2008	2007	2008	2007
(Thousands)
Operating Revenues
Retail	$307,876	$289,528	$1,101,405	$1,088,661
Wholesale	1,183	2,438	6,956	5,934
Other	6,507	2,438	19,405	(2,809)
Total Operating Revenues	$315,566	$294,404	$1,127,766	$1,091,786
Operating Expenses
Natural gas purchased	$195,634	$174,232	$742,517	$712,738
Other operating and maintenance expenses	64,055	60,551	121,190	116,427
Depreciation and amortization	21,383	21,431	42,684	43,526
Other taxes	21,428	20,578	55,955	56,065
Total Operating Expenses	$302,500	$276,792	$962,346	$928,756
Operating Income	$13,066	$17,612	$165,420	$163,030

Three Months

Operating Revenues : The $21 million increase in operating revenues for the second quarter of 2008, was primarily the result of:

• An increase of $44 million resulting from higher market prices for natural gas, and
• An increase of $4 million in other revenues.

Those increases were partially offset by:

• A decrease of $27 million resulting from a 12% decrease in retail deliveries, excluding transportation, primarily due to warmer weather.

Operating Expenses : The $26 million increase in operating expenses for the second quarter of 2008, was primarily the result of:

• An increase of $46 million in natural gas purchases resulting from higher market prices,
• An increase of $2 million due to higher bad debt reserves, and
• An increase of $2 million consisting of various operating and maintenance expense items.

Those increases were partially offset by:

• A decrease of $24 million in natural gas purchases due to lower retail deliveries.

Six Months

Operating Revenues : The $36 million increase in operating revenues for the six months ended June 30, 2008, was primarily the result of:

• An increase of $60 million resulting from higher market prices for natural gas that were passed on to customers,
• An increase of $15 million in other revenues, primarily due to lower accruals under various margin sharing mechanisms,
• An increase of $9 million resulting from higher weather normalization accruals, and
• An increase of $5 million in transportation revenues, primarily as a result of more retail customers taking supply from other providers.

Those increases were partially offset by:

• A decrease of $53 million resulting from a 7% decrease in retail deliveries, excluding transportation. About two-thirds of that decrease was due to warmer temperatures in 2008 than in 2007.

Operating Expenses : The $34 million increase in operating expenses for the six months ended June 30, 2008, was primarily the result of:

• An increase of $78 million in natural gas purchases resulting from higher market prices,
• An increase of $5 million in operating and maintenance expenses primarily due to higher bad debt expense, and
• An increase of $2 million in natural gas purchases resulting from an increase in wholesale sales.

Those increases were partially offset by:

• A decrease of $51 million in natural gas purchases due to lower deliveries.

 

Operating Results for the Energy Marketing Business

	Three Months		Six Months
Periods ended June 30,	2008	2007	2008	2007
(Thousands)
Electricity sales (MWh)	1,021	1,118	2,136	2,167
Natural gas sales (Dth)	950	1,005	4,584	4,961
Operating Revenues
Electric	$101,540	$86,591	$204,400	$180,648
Natural gas	16,046	12,002	54,545	53,873
Total Operating Revenues	$117,586	$98,593	$258,945	$234,521
Operating Expenses
Electricity purchased	$96,979	$82,729	$194,968	$171,773
Natural gas purchased	15,108	11,321	50,230	51,720
Other operating expenses	3,797	3,566	8,162	6,688
Total Operating Expenses	$115,884	$97,616	$253,360	$230,181
Operating Income	$1,702	$977	$5,585	$4,340

Three Months

Operating Revenues : The $19 million increase in operating revenues for the second quarter of 2008 was primarily the result of:

• An increase of $23 million due to higher electricity prices, and
• An increase of $5 million due to higher natural gas prices.

Those increases were partially offset by:

• A decrease of $8 million due to lower electricity sales because of warmer weather and attrition of some large commercial customers, and
• A decrease of $1 million due to lower natural gas sales because of warmer weather.

Operating Expenses : The $18 million increase in operating expense for the second quarter of 2008 was primarily the result of:

• An increase of $21 million in electricity purchased due to higher prices, and
• An increase of $4 million in natural gas purchased due to higher prices.

Those increases were partially offset by:

• A decrease of $7 million in electricity purchased because of lower sales due to warmer weather and attrition of some large commercial customers, and

• A decrease of $1 million in natural gas purchased due to lower natural gas sales because of warmer weather.

Six Months

Operating Revenues : The $24 million increase in operating revenues for the six months ended June 30, 2008, was primarily the result of:

• An increase of $26 million due to higher electricity prices, and
• An increase of $5 million due to higher natural gas prices.

Those increases were partially offset by:

• A decrease of $3 million due to lower retail electricity sales resulting from attrition in connection with some large commercial customers, and
• A decrease of $4 million due to decreased natural gas sales resulting from warmer weather and customer attrition.

Operating Expenses : The $23 million increase in operating expense for the six months ended June 30, 2008, was primarily the result of:

• An increase of $26 million in purchased electricity due to higher prices,
• An increase of $2 million in purchased natural gas due to higher prices, and
• An increase of $1 million in other operating expenses due to higher collection costs.

Those increases were partially offset by:

• A decrease of $2 million in purchased electricity due to lower electricity sales, and
• A decrease of $4 million in natural gas purchases due to lower natural gas sales.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk
(See our report on Form 10-K for the fiscal year ended December 31, 2007, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

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 fixed rate option, which effectively combines delivery and supply service at a fixed price. NYSEG uses electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity required to serve customers who select the fixed rate option. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. Owned electric generation and long-term supply contracts reduce NYSEG's exposure, and significantly reduce RG&E's exposure, to market fluctuations for procurement of their fixed rate option electricity supply.

As of July 2008 the expected load for NYSEG's fixed rate option customers is 83% hedged for August through December 2008. A fluctuation of $1.00 per MWh in the average price of electricity would change NYSEG's earnings less than $140,000 for August through December 2008. RG&E expects to meet its fixed price load obligations for 2008 with owned generation or long-term supply contracts. The estimated percentage of NYSEG's hedged load and RG&E's expectation that it can meet load requirements with current resources are based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecasts.

Accumulated other comprehensive income associated with our financial electricity contracts at June 30, 2008, was $54 million, reflecting an increase of $31 million since December 31, 2007. The increase is primarily a result of wholesale market price increases for electricity in the New York market. Other comprehensive income for the remainder of 2008 will have no effect on future net income because we only use financial electricity contracts to hedge the price of our electric load requirements for customers who have chosen a fixed rate option.

NYSEG also uses electricity contracts to manage fluctuations in prices for electricity in order to provide price stability to customers served under the variable price option. NYSEG includes the cost or benefit of those contracts in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of electricity hedge contracts for variable rate customers as regulatory assets or regulatory liabilities. Hedge assets and offsetting regulatory liabilities for these electricity contracts increased by $10 million from December 31, 2007.

All of our natural gas utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices in order to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts as regulatory assets or regulatory liabilities. Hedging assets and offsetting regulatory liabilities for natural gas futures and forwards increased by $87 million from December 31, 2007.

Energetix and NYSEG Solutions, Inc. 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 July 2008 the energy marketing subsidiaries' expected fixed price loads were 90% hedged for August through December 2008. A fluctuation of $1.00 per MWh in the average price of electricity would change their earnings less than $113,000 for August through December 2008. 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 the load compared to the load forecasts.

NYSEG, RG&E, Energetix and NYSEG Solutions face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are dependent on a counterparty's or the counterparty guarantor's applicable credit rating. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.

We use interest rate swap agreements to manage the risk of increases in variable interest rates and to maintain desired fixed-to-floating rate ratios. We record amounts paid and received under those agreements as adjustments to the interest expense of the specific debt issues. NYSEG and RG&E are currently in the process of restructuring their auction rate debt portfolios to reduce exposure to variable rate debt.

We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of default on or termination of any one contract. Our obligation to return cash collateral under master netting arrangements was $13 million at June 30, 2008, and $7 million at December 31, 2007.

Item 4.    Controls and Procedures

Our principal executive officer and principal financial officer evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. "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 SEC'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, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

We 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. Our system of internal control over financial reporting contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. There was no change in our internal control over financial reporting that occurred during the most recent fiscal quarter that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.    Legal Proceedings

Homer City : On June 23, 2008, NYSEG received a letter from subsidiaries of Edison Mission Energy regarding a notice of violation (NOV) from the United States Environmental Protection Agency (EPA) claiming that certain modifications to the Homer City Electric Generation Station (Homer City) during the time it was owned by NYSEG and Pennsylvania Electric Company were done in violation of the EPA's new source review regulations. Homer City was sold in 1999 to Edison Mission Energy by NYSEG and Pennsylvania Electric Company. Edison Mission Energy asserts that it is entitled to indemnification for fines, penalties and certain costs arising out of the violations alleged in the NOV under the terms of the asset purchase agreement for Homer City. This appears to be the same claim that Edison Mission Energy made to NYSEG in October 2000. At that time NYSEG believed that it did not retain liability for these material claims. NYSEG continues to believe that the costs sought by Edison Mission Energy are not liabilities of NYSEG.

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

(c) Issuer Purchases of Equity Securities

	(a)      Total number of shares purchased (1)		(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, 2008 to   April 30, 2008)	7,815 (1)		$23.93		-			-
Month #2   (May 1, 2008 to   May 31, 2008)	4,631 (2)		$24.20		-			-
Month #3   (June 1, 2008 to   June 30, 2008)	5,915 (2)		$26.90		-			-
Total	18,361		$24.96		-			-
(1)  Represents 4,729 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 3,086 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)  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.

Item 6 .    Exhibits

See Exhibit Index .

 

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.

Date:  July 31, 2008

ENERGY EAST CORPORATION                   (Registrant) By    /s/Robert D. Kump                                          Robert D. Kump            Senior Vice President and Chief Financial Officer            (Principal Accounting Officer)

 

EXHIBIT INDEX

The following exhibits are delivered with this report:

Exhibit No.	Description of Exhibit
31-1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
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).

Energy East agrees to furnish to the SEC, upon request, a copy of the Revolving Credit Agreement dated as of July 10, 2008, among NYSEG, certain lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. The total amount of securities authorized under such agreement does not exceed 10% of the total assets of Energy East.