UIL (UIL) 8-K Financial Statements and Exhibits

EXHIBIT 99.1

Connecticut Energy Corporation and CTG Resources, Inc.

CombinedFinancial Statements

For the Year Ended December 31, 2009 (Successor), the period

September 17, 2008 to December 31, 2008 (Successor), the period

January 1, 2008 to September 16, 2008 (Predecessor), and the Year

Ended December 31, 2007 (Predecessor)

Connecticut Energy Corporation and CTG Resources, Inc.

Index

Combined Financial Statements:	Page(s)
Reports of Independent Auditors
Combined Statements of Income(1)	1
Combined Statements of Comprehensive Income(1)	1
Combined Balance Sheets at December 31, 2009 and 2008 (Successor)	2 – 3
Combined Statements of Cash Flows(1)	4
Combined Statements of Changes in Equity(1)	5 – 6
Notes to Combined Financial Statements	7 – 37

(1)   For the year ended December 31, 2009 (Successor), the period September 17, 2008 to December 31, 2008 (Successor), the period January 1, 2008 to September 16, 2008 (Predecessor), and the year ended December 31, 2007 (Predecessor).

1

To the Shareholder and Boards of Directors

of Connecticut Energy Corporation and CTG Resources, Inc.:

In our opinion, the accompanying combined balances sheets and the related combined statements of income, of comprehensive income, of cash flows and of changes in equity present fairly, in all material respects, the financial position of Connecitcut Energy Corporation and CTG Resources, Inc. (the "Combined Company") at December 31, 2009 and December 31, 2008, and the results of their operations and their cash flows for the year ended December 31, 2009 and the period from September 17, 2008 to December 31, 2008 (the "successor periods") in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Combined Company's management.  Our responsibility is to express an option on these financial statements based on our audits.  We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America.  Those standards require that we plan and perfom the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by managment, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

July 24, 2010

To the Shareholder and Boards of Directors

of Connecticut Energy Corporation and CTG Resources, Inc.:

In our opinion, the accompanying combined statements of income, of comprehensive income, of cash flows and of changes in equity present fairly, in all material respects, the results of operations and cash flows of Connecitcut Energy Corporation and CTG Resources, Inc. (the "Combined Company") for the period from January 1, 2008 to September 16, 2008 and the year ended December 31, 2007 (the "predecessor periods") in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsiblity of the Combined Company's management.  Our responsiblity is to express and opinion on these financial statements based on our accepted in the United States of America.  Those standards require that we plan and perform the audit misstatement.  An audit inc ludes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the financial statements, effective January 1, 2008, the Combined Company adopted.  Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements.

/s/ PricewaterhouseCoopers LLP

July 24, 2010

Connecticut Energy Corporation and CTG Resources, Inc.

		Successor					Predecessor
		Year Ended December 31, 2009			Period September 17 to December 31, 2008		Period January 1, to September			Year Ended December
(Thousands)
Operating Revenues
Sales and services	$	713,701		$	273,051	$	651,054		$	843,359
Operating Expenses
Natural gas purchased		381,375			171,179		392,254			484,564
Other operating expenses		161,122			45,105		103,355			136,300
Maintenance		20,320			5,309		10,722			15,707
Depreciation and amortization		51,061			12,956		31,197			44,782
Other taxes		48,736			15,537		36,922			50,387
Total Operating Expenses		662,614			250,086		574,450			731,740
Operating Income		51,087			22,965		76,604			111,619
Other (Income)		(7,462	)		(2,081		(5,928	)		(7,069	)
Other Deductions		1,258			1,571		13,908			3,218
Interest Charges		31,865			9,577		23,502			33,932
Income Before Income Taxes		25,426			13,898		45,122			81,538
Income Taxes		(12,160	)		4,470		11,507			26,428
Net Income		37,586			9,428		33,615			55,110
Less: Preferred Stock Dividends of   Subsidiary, Noncontrolling Interests		39			26		39			52
Net Income Attributable to Other   Noncontrolling Interests		627			99		261			410
Net Income Attributable to CEC and CTG	$	36,920		$	9,303	$	33,315		$	54,648

The accompanying notes are an integral part of our combined financial statements.

Connecticut Energy Corporation and CTG Resources, Inc.

Combined Statements of Comprehensive Income(1)

	Successor					Predecessor
	Year Ended  December  31, 2009		Period  September 17,  to December  31, 2008			Period  January 1, to  September 16,  2008			Year Ended  December  31, 2007
(Thousands)
Net Income	$	37,586	$	9,428		$	33,615		$	55,110
Other Comprehensive Income (Loss),   Net of Tax		1,766		(1,330	)		(956	)		1,153
Comprehensive Income		39,352		8,098			32,659			56,263
Less: Preferred Stock Dividends of   Subsidiary, Noncontrolling Interests		39		26			39			52
Comprehensive Income Attributable to   Other Noncontrolling Interests		627		99			261			410
Comprehensive Income Attributable to   CEC and CTG	$	38,686	$	7,973		$	32,359		$	55,801

The accompanying notes are an integral part of our combined financial statements.

(1)For the year ended December 31, 2009 (Successor), the period September 17, 2008 to December 31, 2008 (Successor), the period January 1, 2008 to September 16, 2008 (Predecessor), and the year ended December 31, 2007 (Predecessor).

1

Connecticut Energy Corporation and CTG Resources, Inc.

Combined Balance Sheets (Successor)

December 31,	2009		2008
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$	25,367	$	29,616
Accounts receivable and unbilled revenues, net		128,705		203,663
Accounts receivable affiliate		1,441		2,066
Notes receivable affiliate		5,700		7,000
Natural gas in storage, at average cost		145,362		217,697
Materials and supplies, at average cost		1,407		1,672
Deferred income taxes		141		1,245
Derivative assets		306		316
Prepaid taxes		33,371		4,258
Prepayments and other current assets		10,910		9,507
Total Current Assets		352,710		477,040
Utility Plant, at Original Cost
Natural gas		1,315,749		1,309,712
Less accumulated depreciation		430,702		383,312
Net Utility Plant in Service		885,047		926,400
Construction work in progress		1,370		208
Total Utility Plant		886,417		926,608
Other Property and Investments
Other property and investments		58,470		58,584
Investment in wind farms		304,821		-
Total Other Property and Investments		363,291		58,584
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes		86,606		75,864
Deferred income taxes		7,947		6,261
Environmental remediation costs		3,342		3,823
Deferred purchased gas		34,674		23,382
Low income program		47,121		39,953
Pension and other postretirement benefits		162,270		176,990
Other		36,890		29,677
Total regulatory assets		378,850		355,950
Other assets
Goodwill		459,873		460,729
Other		17,649		24,270
Total other assets		477,522		484,999
Total Regulatory and Other Assets		856,372		840,949
Total Assets	$	2,458,790	$	2,303,181

The accompanying notes are an integral part of our combined financial statements.

2

Connecticut Energy Corporation and CTG Resources, Inc.

Combined Balance Sheets (Successor)

December 31,	2009			2008
(Thousands, except shares)
Liabilities
Current Liabilities
Current portion of long-term debt	$	40,000			-
Notes payable		-		$	122,750
Notes payable to affiliate		16,100			27,700
Accounts payable and accrued liabilities		11,649			15,039
Accounts payable, natural gas purchased		54,494			92,617
Accounts payable to affiliate		7,909			5,373
Interest accrued		6,211			5,721
Taxes accrued		25,487			19,279
Derivative liabilities		-			652
Customer deposit		10,145			8,895
Other		18,929			16,179
Total Current Liabilities		190,924			314,205
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligations		189,555			194,293
Deferred income taxes		39,854			30,486
Pension benefits		23,730			26,987
Other		64,657			55,225
Total regulatory liabilities		317,796			306,991
Other liabilities
Deferred income taxes		235,212			168,698
Pension and other postretirement benefits		136,124			143,561
Asset retirement obligations		17,530			18,287
Other		4,003			31,191
Total other liabilities		392,869			361,737
Total Regulatory and Other Liabilities		710,665			668,728
Long-term debt		344,000			378,900
Total Liabilities		1,245,589			1,361,833
Commitments and Contingencies
Preferred Stock of Subsidiary
Redeemable preferred stock, noncontrolling interests		750			750
CEC and CTG Common Stock Equity  Common stock ($1 par value, 1,000 shares authorized   and outstanding for CEC; no par value, 1,000 shares   authorized and outstanding for CTG; at   December 31, 2009 and 2008)		2			2
Capital in excess of par value		1,183,228			927,688
Retained earnings		23,223			9,303
Accumulated other comprehensive (loss)		(184	)		(1,950	)
Total CEC and CTG Common Stock Equity		1,206,269			935,043
Other Noncontrolling Interests		6,182			5,555
Total Equity		1,212,451			940,598
Total Liabilities and Equity	$	2,458,790		$	2,303,181

The accompanying notes are an integral part of our combined financial statements.

3

Connecticut Energy Corporation and CTG Resources, Inc.

Combined Statements of Cash Flows

	Successor						Predecessor
	Year Ended  December  31, 2009			Period  September 17,  to December  31, 2008			Period  January 1, to  September  16, 2008			Year Ended  December  31, 2007
(Thousands)
Operating Activities
Net income	$	37,586		$	9,428		$	33,615		$	55,110
Adjustments to reconcile net income to net   cash provided by operating activities
Depreciation and amortization		34,408			13,705			32,024			46,505
Amortization of regulatory and other      assets and liabilities, net		(1,264	)		127			(513	)		2,009
Deferred income taxes and investment      tax credits, net		69,550			(1,464	)		(9,817	)		6,528
Bridgeport pipeline contract impairment		7,312			-			-			-
Pension expense (income)		7,564			(13	)		1,346			3,754
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net		76,860			(81,768	)		76,714			(21,597	)
Inventories		72,600			9,496			(94,847	)		11,531
Prepayments and other current assets		(7,117	)		1,038			(3,642	)		3,511
Accounts payable and accrued liabilities		(38,454	)		29,818			(25,150	)		11,641
Interest accrued		539			(5,090	)		3,815			(194	)
Taxes accrued		(20,344	)		13,082			4,956			(22,712	)
Other current liabilities		(2,128	)		(1,933	)		3,312			6,542
Pension contribution		(4,700	)		-			-			(3,000	)
Changes in other assets
Customer hardship arrearage forgiveness and      related programs		(30,619	)		(5,290	)		(13,110	)		(16,668	)
Deferred gas costs		(1,284	)		(22,199	)		25,364			2,231
Other		(9,505	)		(1,344	)		(2,701	)		(1,603	)
Changes in other liabilities
Nonfirm margin sharing		15,839			3,425			18,311			18,411
Other		6,188			7,447			4,400			542
Net Cash Provided by (Used in)     Operating Activities		213,031			(31,535	)		54,077			102,541
Investing Activities
Utility plant additions		(40,261	)		(15,865	)		(45,730	)		(54,805	)
Proceeds from sale of Capitol Area System		10,624			-			-			-
Notes receivable, affiliate		1,300			(7,000	)		-			-
Other property additions		(60	)		(2,094	)		(8,704	)		(1,946	)
Investment in wind farms		(304,821	)		-			-			-
Investments available for sale, net		12,687			(1,198	)		(706	)		(412	)
Net Cash Used in Investing Activities		(320,531	)		(26,157	)		(55,140	)		(57,163	)
Financing Activities
Equity contribution from parent		305,400			-			-			-
Issuance of first mortgage bonds		-			-			-			40,000
Repayment of first mortgage bonds		-			(35,000	)		-			(65,000	)
Long-term note issuances		20,000			50,000			7,400			20,000
Long-term note repayments		(14,900	)		(49,900	)		(2,500	)		(24,000	)
Notes payable three months or less, net		(134,350	)		97,190			9,944			7,000
Liquidating dividend		(49,860	)		-			-			-
Dividends paid on preferred stock of subsidiary,    noncontrolling interests		(39	)		(26	)		(39	)		(52	)
Dividends paid on common stock		(23,000	)		-			(15,000	)		(23,500	)
Net Cash Provided by (Used in)      Financing Activities		103,251			62,264			(195	)		(45,552	)
Net (Decrease) Increase in Cash and    Cash Equivalents		(4,249	)		4,572			(1,258	)		(174	)
Cash and Cash Equivalents, Beginning of Period		29,616			25,044			26,302			26,476
Cash and Cash Equivalents, End of Period	$	25,367		$	29,616		$	25,044		$	26,302

The accompanying notes are an integral part of our combined financial statements.

4

Connecticut Energy Corporation and CTG Resources, Inc.

Combined Statements of Changes in Equity

(Predecessor)

(Thousands, except shares)	Common Stock  Outstanding  at Par Value(1)  Shares Amount				Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive (Loss) Income			Other Noncontrolling Interests		Compre- hensive Income (Loss)*			Total
Balance, January 1, 2007		2,000	$	2	$	805,077	$	96,801		$	(817	)	$	4,785				$	905,848
Net income*								54,648						410	$	55,058			55,058
Other comprehensive income, net of tax											1,153					1,153			1,153
Comprehensive income*															$	56,211			56,211
Equity contribution from parent						379													379
Common stock dividends								(23,500	)										(23,500	)
Balance, December 31, 2007		2,000		2		805,456		127,949			336			5,195					938,938
Net income*								33,315						261	$	33,576			33,576
Other comprehensive (loss), net of tax											(956	)				(956	)		(956	)
Comprehensive income*															$	32,620			32,620
Cumulative-effect adjustment, change in     accounting for collateral assignment     split-dollar life insurance								(2,286	)										(2,286	)
Equity contribution from parent						686													686
Common stock dividends								(15,000	)										(15,000	)
Merger transactions, net						121,546		(143,978	)										(22,432	)
Balance, September 16, 2008		2,000	$	2	$	927,688		-		$	(620	)	$	5,456				$	932,526

The accompanying notes are an integral part of our combined financial statements.

(1) Par value of common stock: $1 for Connecticut Energy Corporation; no par value for CTG Resources, Inc.

*Amounts do not include Preferred Stock Dividends of Subsidiary, Noncontrolling Interests of $52 for 2007 and $39 for the period January 1, to September 16, 2008.

5

Connecticut Energy Corporation and CTG Resources, Inc.

Combined Statements of Changes in Equity

(Successor)

(Thousands, except shares)	Common Stock Outstanding at Par Value(1) Shares Amount				Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive (Loss) Income			Other Noncontrolling Interests		Compre- hensive Income (Loss)*			Total
Balance, September 17, 2008		2,000	$	2	$	927,688			-		$	(620	)	$	5,456				$	932,526
Net income*								$	9,303						99	$	9,402			9,402
Other comprehensive (loss), net of tax												(1,330	)				(1,330	)		(1,330	)
Comprehensive income*																$	8,072			8,072
Balance, December 31, 2008		2,000		2		927,688			9,303			(1,950	)		5,555					940,598
Net income*									36,920						627	$	37,547			37,547
Other comprehensive income, net of tax												1,766					1,766			1,766
Comprehensive income*																$	39,313			39,313
Equity contribution from parent						305,400														305,400
Liquidating dividend						(49,860	)													(49,860	)
Common stock dividends									(23,000	)										(23,000	)
Balance, December 31, 2009		2,000	$	2	$	1,183,228		$	23,223		$	(184	)	$	6,182				$	1,212,451

The accompanying notes are an integral part of our combined financial statements.

(1) Par value of common stock: $1 for Connecticut Energy Corporation; no par value for CTG Resources, Inc.

*Amounts do not include Preferred Stock Dividends of Subsidiary, Noncontrolling Interests of $26 for the period September 17, to December 31, 2008, and $39 for 2009.

6

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Note 1. Significant Accounting Policies

Background: Connecticut Energy Corporation (CEC or the company) and CTG Resources, Inc. (CTG or the company) are wholly-owned subsidiaries of Iberdrola USA, Inc. (Iberdrola USA). (We may also refer to CEC and CTG combined as “we,” “our” or “us.”)

CEC’s principal subsidiary is The Southern Connecticut Gas Company (SCG), which is a regulated utility that conducts natural gas transportation and distribution operations in Connecticut serving approximately 175,000 customers in its service territory of approximately 560 square miles with a population of approximately 808,000. SCG's service territory extends along the southern Connecticut coast from Westport to Old Saybrook and includes the communities of Bridgeport and New Haven. SCG’s natural gas system consists of transmission and distribution lines, all of which are located in the state of Connecticut. The transmission distribution system consists of 3,751 miles of pipeline. SCG operates under the authority of the Connecticut Department of Public Utility Control (DPUC) in Connecticut and is also subjec t to regulation by the Federal Energy Regulatory Commission (FERC).

CEC’s other principal subsidiary is CNE Energy Services Group, Inc. (CNE Energy) which has an interest in two small natural gas pipelines that serve power plants in Connecticut. CNE Energy has a long-term lease for a liquefied natural gas plant that serves the peaking gas markets in the Northeast and has an equity interest in an energy technology venture partnership. In addition, in April 2009 CEC acquired an interest in various wind farms owned by Aeolus Wind Power V LLC (Aeolus V). (See Note 12.)

CTG’s principal subsidiary is Connecticut Natural Gas Corporation (CNG), which is a regulated utility that conducts natural gas transportation and distribution operations in Connecticut serving approximately 155,000 customers in its service territory of approximately 575 square miles with a population of approximately 706,000, principally in the greater Hartford-New Britain area and Greenwich. CNG operates under the authority of the DPUC in Connecticut and is also subject to regulation by the FERC.

CTG also owns TEN Companies, Inc. (TEN). TEN provides district heating and cooling services in the downtown area of Hartford, Connecticut. TEN also leases energy equipment to commercial and residential customers and provides electric power and steam to Hartford Hospital. TEN’s wholly-owned subsidiary, TEN Transmission Company, owns a 4.87% share of the Iroquois Gas Transmission System, which it accounts for using the equity method due to its participation on the management committee. The transmission system is a 411-mile interstate natural gas pipeline extending from the U.S. Canadian border at Waddington, NY through western Connecticut and Long Island Sound to Hunts Point, NY.

We have evaluated events or transactions that occurred after December 31, 2009, for inclusion in these financial statements through July 23, 2010, which is the date these financial statements were available to be issued. (See “New accounting standards adopted,” “Subsequent events,” below.)

Effective September 16, 2008, Energy East Corporation (Energy East) became a wholly-owned subsidiary of Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain. The merger was a business combination whereby Energy East and its subsidiaries, including CEC and CTG, became wholly-owned subsidiaries of Iberdrola. The merger was completed through the acquisition by a subsidiary of Iberdrola of all the outstanding common

7

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

stock of Energy East. On December 1, 2009, Energy East changed its legal and operating name to Iberdrola USA, Inc.

On May 25, 2010, UIL Holdings Corporation entered into an agreement to purchase CEC and CTG as well as Berkshire Energy Resources, another natural gas distribution utility owned by Iberdrola USA. Pursuant to the agreement, Iberdrola USA will retain the assets of CNE Energy and TEN at the time of the transaction. The purchase is subject to various state and federal approvals. We expect the sale to be completed by the first quarter of 2011. UIL agreed to pay $1,156 million for CTG and CEC, which includes debt to be assumed.

Accounts receivable: Accounts receivable at December 31 include unbilled revenues of $41 million for 2009 and $62 million for 2008, and are shown net of an allowance for doubtful accounts at December 31 of $7.4 million for 2009 and $13.6 million for 2008. Accounts receivable do not bear interest, although late fees may be assessed. Bad debt expense was $34.4 million for 2009, $29.3 million for the period January 1, to September 16, 2008, $10.3 million for the period September 17, to December 31, 2008, and $31.3 million for 2007.

Unbilled revenues represent estimates of receivables for products and services provided but not yet billed. The estimates are determined based on various assumptions, such as current month energy load requirements, billing rates by customer classification and delivery loss factors. Changes in those assumptions could significantly affect the estimates of unbilled revenues.

The allowance for doubtful accounts is our best estimate of the amount of probable creditlosses in our existing accounts receivable, determined based on experience for each service region and operating segment and other economic data. Each month we review our allowance for doubtful accounts and past due accounts over 90 days and/or above a specified amount, and review all other balances on a pooled basis by age and type of receivable. When we believe that a receivable will not be recovered, we charge off the account balance against the allowance. Changes in assumptions about input factors such as economic conditions and customer receivables, which are inherently uncertain and susceptible to change from period to period, could significantly affect the allowance for doubtful a ccounts estimate.

Asset retirement obligations: We record the fair value of the liability for an asset retirement obligation (ARO) and/or a conditional ARO in the period in which it is incurred and capitalize the cost by increasing the carrying amount of the related long-lived asset. We adjust the liability to its present value periodically over time, and depreciate the capitalized cost over the useful life of the related asset. Upon settlement we will either settle the obligation at its recorded amount or incur a gain or a loss. We defer any timing differences between rate recovery and depreciation expense as either a regulatory asset or a regulatory liability.

The term conditional ARO refers to an entity's legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred.

Our ARO including our estimated conditional ARO was $18 million at December 31, 2009, and 2008. It consists primarily of obligations related to removal or retirement of: asbestos, polychlorinated biphenyl (PCB) contaminated equipment, gas pipeline and cast iron gas mains. The long-lived assets associated with our AROs are gas storage property, distribution property and other property.

8

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Accrued removal obligations: We meet the accounting requirements concerning regulated operations, and recognize a regulatory liability, for financial reporting purposes only, for the difference between removal costs collected in rates and actual costs incurred. We classify those amounts as accrued removal obligations.

Statements of cash flows: We consider all highly liquid investments with an original maturity date of three months or less to be cash equivalents and include those investments in cash and cash equivalents.

		Successor					Predecessor
Supplemental Disclosure of Cash Flows Information		Year Ended December 31, 2009			Period  September 17, to  December 31,  2008		Period  January 1, to  September 16,  2008		Year Ended December 31, 2007
(Thousands)
Cash paid during the period:
Interest, net of amounts capitalized	$	27,724		$	10,104	$	20,033	$	30,797
Income taxes, net of benefits received	$	(62,366	)	$	1,797	$	14,315	$	39,898

Depreciation and amortization: We determine depreciation expense substantially using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal. The weighted-average service lives of certain classifications of property are: production property – 34 years, distribution property - 53 years, gas storage property - 71 years, and other property - 24 years. Our depreciation accruals were equivalent to 3.3% of average depreciable property for 2009 and 2008, and 3.4% for 2007.

We charge repairs and minor replacements to operating expense, and capitalize renewals and betterments, including certain indirect costs. We charge the original cost of utility plant retired or otherwise disposed of to accumulated depreciation.

Bridgeport pipeline contract impairment:In 1998 CNE Energy, a subsidiary of CEC, provided the funds for the construction of an 11.5 mile long pipeline in Bridgeport, Connecticut, which is subject to a 20 year gas transmission agreement (Agreement) with an unrelated entity. CNE Energy recorded the $12.8 million total cost of construction of the pipeline as an intangible asset (contract interest) on its balance sheet, which it then began to amortize over the 20 year life of the project. SCG constructed the pipeline and has owned and operated it since its completion. In addition to funding the pipeline construction costs, CNE Energy has paid all operating and maintenance c osts related to the pipeline project. As a result of Energy East’s acquisition of SCG and CNE Energy in February 2000, the value of the investment in the pipeline was assessed and CNE Energy recorded an intangible asset of $2.4 million. CNE Energy has been amortizing the valuation adjustment over the remaining term of the Agreement, since February 2000.

In February 1998 the DPUC issued a decision concerning the allocation of revenues during the first 10 years of the Agreement, allocating a portion to SCG for the benefit of its ratepayers with the remaining portion retained by CNE Energy. The original DPUC decision required SCG to petition the DPUC by July 1, 2008, for an adjustment to the allocation of revenues for the second 10 years of the Agreement. The DPUC issued a decision on April 1, 2009, reducing the annual revenue allocation to CNE Energy for the remaining term of the Agreement. Based on its estimate of undiscounted cash flows for the remaining years, CNE Energy determined that the combined $7.1 million carrying amount of the contract interest and valuation adjustment was not

9

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

recoverable, and impaired the entire net carrying amount.  In addition, because substantially all of its economic activity is derived from the Bridgeport contract, CNE Energy also impaired $0.2 million of net goodwill in 2009. The combined pretax impairments totaling approximately $7.3 million are included in depreciation and amortization on the income statement. The total after-tax effect of the impairments is approximately $4.7 million.

Goodwill: We perform an annual goodwill impairment test during the third quarter of each year. We update the test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The annual analysis of the potential impairment of goodwill requires a two step process. Step one of the impairment test involves comparing the fair values of reporting units with their aggregate carrying values, including goodwill. If the carrying amount of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment loss. If the carrying amount is less tha n fair value, further testing of goodwill impairment is not performed.

Step two of the goodwill impairment test involves comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Under step two, determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The difference between the fair value of the entire reporting unit as determined in step one and the net fair value of all identifiable assets and liabilities represents the implied fair value of goodwill. A goodwill impairment charge, if any, would be the difference between the carrying amount of goodwill and the implied fair value of goodwill upon the completion of step two.

For purposes of the step one analyses, we base the determination of the fair value of reporting units on the income approach, which estimates fair value based on discounted future cash flows. Based on the completion of step one of the annual impairment analysis, management determined that the fair value of each reporting unit was greater than its carrying value. (See Note 2.)

We may be required to recognize an impairment of goodwill in the future due to market conditions or other factors related to our performance. Those market events could include a decline in the forecasted results in our business plan, significant adverse rate case results, changes in capital investment budgets or changes in interest rates that could permanently impair the fair value of a reporting unit. Recognition of impairments of a significant portion of goodwill would negatively affect our reported results of operations and total capitalization, the effect of which could be material and could make it more difficult to maintain our credit ratings, secure financing on attractive terms, maintain compliance with debt covenants and meet expectations of our regulators.

Liquidating dividend: In 2009 CEC declared and paid a liquidating dividend of $49.9 million to Iberdrola USA.

New accounting standards adopted: We have adopted new accounting standards issued by the Financial Accounting Standards Board (FASB) as explained below.

Collateral assignment split-dollar life insurance: Effective January 1, 2008, we began applying a new accounting standard, ratified by the FASB in late March 2007, that requires an employer to recognize a liability for a postretirement benefit related to a collateral assignment split-dollar life

10

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

insurance arrangement. In such an arrangement, the employee, versus the employer, owns and controls the insurance policy. The new standard also requires that an employer recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement. CNG has collateral assignment split-dollar life insurance arrangements. We elected to recognize the effects of the change in accounting principle through a cumulative-effect adjustment that resulted in a decrease in retained earnings of $2.3 million. The change did not affect our results of operation or cash flows.

Fair value measurements: The FASB has issued a number of new standards related to fair value measurements. The initial new standard was issued in September 2006, which we adopted effective January 1, 2008, for our fair value measurements of financial assets and financial liabilities. Changes as a result of the application of the new standard relate to the definition of fair value, the methods used to measure fair value, and expanded disclosures about fair value measurements.The new standard 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 req uire any new fair value measurements.

The FASB issued a related new standard in February 2008 that was effective upon issuance. It delayed the effective date of the initial fair value measurement standard 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. It also requires additional disclosures concerning application of the provisions of the initial fair value measurement standard.

In August 2009 the FASB issued an accounting standards update to provide amended guidance concerning the fair value measurement of liabilities. The key provisions of the amendments include clarification about valuation techniques that are to be used in circumstances in which a quoted price in an active market for the identical liability is not available and that a reporting entity is not to include a separate input or adjustments to other inputs to reflect the existence of a restriction that prevents the transfer of a liability. The amended guidance is effective for an entity’s first reporting period (including interim periods) beginning after issuance of the update. We initially began applying the guidance effective October 1, 2009.

Our adoption of the various new standards related to fair value measurements had no effect on our financial position, results of operation or cash flows.

Postretirement benefit plan assets disclosures: In December 2008 the FASB issued a new standard that amends the disclosures an employer is required to provide about its pensions and other postretirement benefits, to improve disclosures about postretirement benefit plan assets. The improved disclosures include objectives and other information concerning fair value measurements of plan assets, and must be provided for fiscal years ending after December 15, 2009. Our application of the new standard beginning with the annual reporting period ending December 31, 2009, did not affect our financial position, results of operation or cash flows. (See Note 11.)

Subsequent events: In May 2009 the FASB issued a new standard to establish principles and requirements concerning accounting for and disclosure of subsequent events – events that occur after the balance sheet date but before the financial statements are issued or available to be issued. The new accounting standard is based on the same principles as in the existing auditing standard, with new terminology as to the evaluation of subsequent events either as of

11

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

the date the financial statements are “issued” or “available to be issued”. We adopted the new standard as of June 30, 2009, and it had no effect on our financial position, results of operation or cash flows. (See “Background,” above, for the required disclosure.)

New accounting standards issued but not yet adopted: New accounting standards issued by the FASB that we have not yet adopted in these financial statements are as explained below.

Variable interest entities:In June 2009 the FASB issued amendments to its revised interpretation concerning consolidation of variable interest entities (VIEs). The amendments clarify, but do not significantly change, the criteria for determining whether an entity meets the definition of a VIE, and change existing consolidation guidance so that qualifying special purpose entities are no longer exempt from consolidation. The amendments require an enterprise to perform ongoing assessments as to whether an entity is a VIE and whether the enterprise is the primary beneficiary of a VIE. Previously such assessments were required only when specified events occurred. The amended standard will alter how an enterprise determines when an entity that is not sufficiently capitalized or not controlled through voting should be consolidated. An enterprise will also be required to perform a qualitative analysis to determine whether it should provide consolidated reporting of an entity based upon the entity’s purpose and design and the enterprise’s ability to direct the entity’s actions. The amended standard also requires enhanced disclosures to provide more transparent information about an enterprise’s involvement in a VIE, and any significant changes in its risk exposure due to that involvement. The amendments are effective at the start of a company’s first fiscal year beginning after November 15, 2009, including interim periods. Earlier application is prohibited. Our adoption of the amendments effective January 1, 2010, did not affect our results of operation, financial position or cash flows.

Disclosures about fair value measurements: In January 2010 the FASB issued amendments to improve disclosures about fair value measurements. New disclosures that will be required include: 1) details of transfers in and out of Levels 1 and Level 2 of the fair value measurement hierarchy, and 2) gross presentation of roll forward activity within Level 3 – separate presentation of information about purchases, sales, issuances and settlements. Entities will also have to provide fair value measurement disclosures for each class of assets and liabilities, as well as disclosures about inputs and valuation techniques for both recurring and nonrecurring Level 2 and Level 3 fair value measurements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2009, except that the disclosures about Level 3 roll forward activity are effective for fiscal years beginning after December 15, 2010, and interim periods within those fiscal years. Our adoption of the amendments as they become effective will not affect our results of operation, financial position or cash flows.

12

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Other (Income) and Other Deductions:

	Successor						Predecessor
	Year Ended December 31, 2009			Period  September 17, to  December 31,  2008			Period  January 1, to  September 16,  2008			Year Ended  December  31, 2007
(Thousands)
Interest and dividend income	$	(537	)	$	(402	)	$	(2,083	)	$	(3,810	)
Carrying costs on regulatory assets		(1,104	)		(281	)		(645	)		(71	)
Equity in partnership interest		(3,685	)		(845	)		(2,424	)		(2,553	)
Life insurance credit		(1,210	)		-			-			-
Miscellaneous		(926	)		(553	)		(776	)		(635	)
Total other (income)	$	(7,462	)	$	(2,081	)	$	(5,928	)	$	(7,069	)
Civic donations	$	132		$	87		$	420		$	434
Losses on energy risk contracts		443			153			467			2,402
Early retirement of debt		-			1,137			12,520			279
Miscellaneous		683			194			501			103
Total other deductions	$	1,258		$	1,571		$	13,908		$	3,218

Early retirement of debt:In October 2008 SCG paid premiums of $11.1 million in connection with the early retirement of $25 million of long-term debt that was subject to special redemption or put options in the event of a change in control. Energy East’s merger with Iberdrola in 2008 qualified for such a change in control. SCG is not allowed rate recovery for such losses on reacquired debt. In addition, in October 2008 TEN paid premiums of $1.6 million in connection with the early retirement of a total of $22.5 million of long-term debt that was subject to similar put options in the event of a change in control. All of the put options were accounted for as embedded derivatives prior to the debt retirement. We did not assign any value to the put options prior to the merger as we believed that any fair value attributable to the put options would have been negligible because of significant uncertainty as to whether the merger would take place. In the fourth quarter of 2008 we also wrote off $1.1 million of unamortized debt expense.

Principles of combination and consolidation: These financial statements represent the combined financial statements of CEC and CTG after eliminating intercompany transactions under the basis of common control since both companies are owned by Iberdrola USA. The financial statements of CEC and CTG consolidate their majority-owned subsidiaries after eliminating intercompany transactions.

Regulatory assets and regulatory liabilities: We currently meet the requirements concerning accounting for regulated operations for our natural gas operations in Connecticut; however, we cannot predict what effect the competitive market or future actions of regulatory entities would have on our ability to continue to do so. If we were to no longer meet the requirements concerning accounting for regulated operations for all or a separable part of our regulated operations, we may have to record certain regulatory assets and regulatory liabilities as an expense or as revenue, or include them in accumulated other comprehensive income.

Pursuant to the requirements concerning accounting for regulated operations we capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future natural gas rates. Substantially all regulatory assets for which funds have been expended are either included in rate base or are accruing carrying costs. We also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.

13

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with our current rate plans.

In 2009 we recorded reserves totaling $1.2 million on existing regulatory assets to reflect management’s assessment of risk and increased uncertainty about the ultimate recovery for certain issues that have not been resolved with our regulators. The resulting charge increased other operating expenses for the period.

Other regulatory assets and other regulatory liabilities consisted of:

December 31,	2009		2008
(Thousands)
Other postretirement benefits	$	11,540	$	12,996
Rate surcharge		3,834		-
Automatic meter reading		3,127		1,384
Other		18,389		15,297
Total other regulatory assets	$	36,890	$	29,677
Nonfirm margin sharing	$	12,478	$	14,163
Asset retirement obligations		7,824		6,584
Deferred natural gas costs		12,522		7,133
Pension		9,771		6,514
Tennessee gas pipeline settlement		5,032		-
Revenue sharing		8,763		13,169
Other		8,267		7,662
Total other regulatory liabilities	$	64,657	$	55,225

Regulatory proceedings:

CNG overearnings and rate filing: In June 2008 CNG filed its monthly financial report with the DPUC showing that it exceeded its allowed return on equity (ROE) by more than 100 basis points for the sixth consecutive monthly period. As a result, the DPUC initiated an overearnings investigation. In August 2008 the DPUC issued a decision ordering CNG to implement a rate decrease of $15 million effective August 6, 2008, and the filing of a rate case by January 1, 2009.

In January 2009 CNG filed an application for a delivery rate increase of $16.2 million or approximately 4.4% over the revenues produced from its existing rate schedules. The DPUC issued CNG’s rate order on July 23, 2009, requiring a rate reduction of 4.2% effective July 31, 2009. CNG appealed the order and the application of new tariffs prescribed by the rate order was temporarily suspended by the court. On January 6, 2010, the Connecticut Superior Court entered a ruling against CNG’s appeal. On January 21, 2010, CNG filed for a continuation of the temporary stay while it pursues an appeal of that decision. On May 28, 2010, CNG appealed the decision to the Connecticut Supreme Court. Oral argument and a decision on the appeal are not expected until the fall of 2010.

SCG overearnings and rate filing:In July 2008 SCG filed its monthly financial report with the DPUC showing that it exceeded its allowed ROE by more than 100 basis points for the sixth consecutive monthly period. As a result, the DPUC initiated an overearnings investigation. In October 2008 the DPUC issued a decision ordering SCG to implement a rate decrease of

14

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

$15 million effective October 24, 2008, and to file pro forma adjustments for the purpose of a surcharge for the period beginning October 24, 2008, through June 30, 2009.

In January 2009 SCG filed an application for a delivery rate increase of $50.1 million or approximately 15.2% over the revenues produced from its existing rate schedules. The DPUC issued SCG’s rate order on July 2, 2009, requiring a rate reduction of 3.2% effective August 19, 2009. SCG appealed the order and the application of new tariffs prescribed by the rate order was temporarily suspended by the Court until it makes a final decision on the appeal. On December 17, 2009, the Court issued an order requiring the DPUC to provide its reasoning for several findings in its decision within 90 days. On April 1, 2010, the Connecticut Superior Court entered a ruling against SCG’s appeal. On April 16, 2010, SCG filed for a continuation of the temporary stay while it pursues an appeal of that decision. On May 28, 201 0, SCG appealed the decision to the Connecticut Supreme Court. Oral argument and a decision on the appeal are not expected until the fall of 2010.

Related party transactions: Iberdrola USA Management Corporation provides various administrative and management services to Iberdrola USA's operating utilities, including CEC and CTG, pursuant to service agreements. The cost of those services is allocated in accordance with methodologies set forth in the service agreements. The cost allocation methodologies vary depending on the type of service provided. Management believes such allocations are reasonable. The cost for services provided to CEC and CTG by Iberdrola USA Management Corporation was approximately $19.3 million for 2009, $15.2 million for the period January 1, to September 16, 2008, $5.1 million for the period September 17, to December 31, 2008, and $17.2 million for 2007.

Revenue recognition: SCG and CNG recognize revenues upon delivery of natural gas and natural gas-related products and services to their customers. Regulated natural gas operations revenues are based on rates authorized by the DPUC. SCG and CNG are required to provide natural gas service to residential customers within their defined service territories and are precluded by Connecticut state law from discontinuing service to hardship residential customers during a winter moratorium period (November – April).

TEN and CNE Energy recognize revenues when services are provided under related contracts.

Risk management: We have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk. We do not hedge the cost of gas for the benefit of customers. SCG also has a weather normalization clause that provides protection from declining revenues due to warmer than normal winter temperatures. CNG does not have such a clause in its rate plan to provide similar protection. CNG entered into a weather derivative contract for the winter period November 1, 2009 through April 30, 2010. According to the terms of the derivative contract, if temperatures are warmer than normal for the co ntract period CNG will receive payment; but if temperatures are colder than normal for the contract period, CNG will make payment. The premium paid is amortized over the term of the contract (six months). The value of the derivative is carried on the balance sheet as a derivative asset with changes in value recorded to the income statement as Other (Income) or Other Deductions. The derivative asset totaled $0.3 million at December 31, 2009. The contract settled in April 2010 and CNG received a payment of $3 million, the maximum allowed under the contract for temperatures that were warmer than normal.

15

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Taxes: We compute our income tax provision on a separate return method. The determination and allocation of our income tax provision and its components are outlined and agreed to in our tax sharing agreement with Iberdrola USA.

Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. We amortize investment tax credits over the estimated lives of the related assets.

We account for sales tax collected from customers and remitted to taxing authorities on a net basis.

We classify all interest and penalties related to uncertain tax positions as income tax expense.

Use of estimates and assumptions: The preparation of our combined financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the combined financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for doubtful accounts and unbilled revenues; (2) asset impairments, including goodwill; (3) depreciable lives of assets; (4) income tax valuation allowances; (5) uncertain tax positions; (6) reserves for professional, workers’ compensation, and comprehensive general insurance liability risks; (7) contingency and litigation reserves; and (8) environmental remediation liability. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates used in the preparation of our combined financial statements will change as new events occur, as more experience is acquired, as additional information is obtained, and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside experts to assist in our evaluation, as considered necessary. Actual results could differ from those estimates.

Note 2. Goodwill

We do not amortize goodwill, but test it for impairment at least annually. Impairment testing includes various assumptions, primarily the discount rate, which is based on an estimate of our marginal, weighted-average cost of capital, and forecasted cash flows. We test the reasonableness of the conclusions of our impairment testing using a range of discount rates and a range of assumptions for long-term cash flows. We had no impairment of goodwill in 2009, 2008 or 2007 as a result of our impairment testing. No impairment was indicated within any of the ranges of assumptions analyzed. Management determined that the fair value of CTG’s and CEC’s goodwill was greater than its carrying value.

16

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

The carrying amount of goodwill as of December 31, 2008 and 2009, is shown in the following table.

	Successor					Predecessor
	Year Ended  December  31, 2009			Period  September 17,  to December  31, 2008		Period  January 1,  to September  16, 2008
(Thousands)
Balance, beginning of period
Goodwill	$	460,729		$	460,729	$	486,914
Accumulated impairment losses		-			-		-
Adjustment for Iberdrola’s purchase of Energy East   in September 2008		-			-		(26,185	)
Goodwill related to TEN’s sale of Capitol Area System		(614	)		-		-
Impairment for Bridgeport		(242	)		-		-
Balance, end of period
Goodwill		460,115			460,729		460,729
Accumulated impairment losses		(242	)		-		-
	$	459,873		$	460,729	$	460,729

We have adjusted goodwill to reflect Iberdrola’s purchase of Energy East. For purposes of the calculation of goodwill applied to CNG and SCG, we allocated the total purchase price paid by Iberdrola based on the fair value of each Energy East reporting unit. The reduction in goodwill was recognized within capital in excess of par value because management determined that no impairment had occurred. We made no valuation adjustments to any of the assets or liabilities of CNG or SCG that are included in the determination of rates because they approximate fair value. There was a $6.2 million increase for some nonutility assets of SCG, primarily related to land values. Our application of purchase price accounting did not have a material effect on our results of operation subsequent to the merger and would have had no material effect if app lied on a pro forma basis to periods prior to the merger.

The above amounts include goodwill of $3.8 million at December 31, 2009, and $4.4 million at December 31, 2008, for TEN; and $0.2 million at December 31, 2008 for CNE Energy. We did not adjust goodwill amounts for TEN and CNE Energy at the time of merger because they approximated fair value.

17

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Note 3. Income Taxes

	Successor						Predecessor
	Year Ended  December  31, 2009			Period  September 17, to  December 31,  2008			Period  January 1, to  September 16,  2008		Year Ended  December  31, 2007
(Thousands)
Current
Federal	$	(71,434	)	$	5,070		$	18,334	$	18,318
State		(10,274	)		861			2,993		1,581
Current taxes charged to expense		(81,708	)		5,931			21,327		19,899
Deferred
Federal		62,300			(234	)		(8,119		5,213
State		7,536			(1,145	)		(1,458		1,718
Deferred taxes charged to expense		69,836			(1,379	)		(9,577		6,931
Investment tax credit adjustments		(288	)		(82	)		(243		(402
Total	$	(12,160	)	$	4,470		$	11,507	$	26,428

The significant decrease in current income tax expense in 2009 as compared to 2008 is driven primarily by the investment in wind farms and a significant one-time tax deduction related to previously capitalized repair costs. The repair costs are temporary differences between book and tax expense and required normalization for SCG and CNG resulting in an offsetting deferred tax expense.

Our tax expense differed from the expense at the statutory rate of 35% due to the following:

	Successor						Predecessor
	Year Ended  December  31, 2009			Period  September 17,  to December  31, 2008			Period  January 1,  to September  16, 2008			Year Ended  December  31, 2007
(Thousands)
Tax expense at statutory rate	$	8,899		$	4,864		$	15,793		$	28,538
Depreciation and amortization     not normalized		151			(420	)		(1,025	)		(930	)
Investment tax credit amortization		(288	)		(94	)		(231	)		(402	)
Removal costs		(1,503	)		(344	)		(842	)		(1,429	)
Medicare subsidy		(191	)		(112	)		(272	)		(226	)
Tax return and audit adjustments		(1,112	)		-			(4,059	)		347
Production tax credits		(14,543	)		-			-			-
State taxes, net of federal benefit		(1,780	)		(185	)		998			2,145
Other, net		(1,793	)		761			1,145			(1,615	)
Total	$	(12,160	)	$	4,470		$	11,507		$	26,428

Income taxes were $21.1 million less in 2009 than they would have been at the federal statutory rate of 35%, $4.7 million less in 2008 and $2.1 million less in 2007. The 2009 effective tax rate was less than the statutory rate primarily due to the recording of a deferred tax asset related to production tax credits generated as a result of the investment in wind farms. The 2008 effective tax rate was less than the statutory rate primarily due to the reversal of reserves resulting from the favorable resolution of federal and state tax audits.

18

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Our consolidated deferred tax assets and liabilities consisted of:

December 31,	2009			2008
(Thousands)
Current Deferred Income Tax Assets (Liabilities)
Derivative (liabilities)	$	(114	)	$	(2	)
Other		255			1,247
Total Current Deferred Income Tax Assets	$	141		$	1,245
Noncurrent Deferred Income Tax Liabilities (Assets)
Property related	$	201,722		$	161,696
Pension		(1,648	)		(20,873	)
Unfunded future income taxes		34,521			30,250
Accumulated deferred investment tax credits		315			400
Other postretirement benefits		(5,699	)		(4,044	)
Investment in wind farms		35,506			-
Other		2,402			25,494
Total Noncurrent Deferred Income Tax Liabilities		267,119			192,923
Valuation allowance		-			-
Less amounts classified as regulatory liabilities
Deferred income taxes		31,907			24,225
Noncurrent Deferred Income Tax Liabilities	$	235,212		$	168,698
Deferred tax assets	$	7,602		$	26,164
Deferred tax liabilities		274,580			217,842
Net Accumulated Deferred Income Tax Liabilities	$	266,978		$	191,678

Reconciliation of Gross Income Tax Reserves	2009		2008
(Thousands)
Balance as of January 1		-		-
Increases for tax positions related to prior years	$	6,792		-
Reductions for tax positions related to prior years		-		-
Decreases for positions related to settlements with taxing authority		-		-
Balance as of December 31	$	6,792		-

The total gross unrecognized tax benefits as of December 31, 2009, were $6.8 million, including gross income tax reserves of $6.6 million and interest of $0.2 million. Including interest, $0.1 million of the total gross unrecognized tax benefits would affect the effective tax rate, if recognized. Gross income tax reserves increased $6.8 million in 2009 primarily due to accelerated deductions taken on the 2008 federal and state tax returns for unit of property.

We have been audited through 2005 for federal income taxes.  The statute of limitations in all state jurisdictions has expired for all years through 2005. Our federal returns for 2006 through 2009 are currently under review. We anticipate that the reviews will be completed in 2011. We cannot predict the ultimate outcome of the reviews.

19

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Note 4. Long-term Debt

At December 31, 2009 and 2008, our long-term debt was:

						Amount  (Thousands)
	Interest Rates			Maturity		2009		2008
First mortgage bonds – SCG
Medium Term Note I		6.880% - 7.950	%		2026 - 2028	$	29,000	$	29,000
Medium Term Note II		6.590% - 7.800	%		2010 - 2011		70,000		70,000
Medium Term Note III		5.772% - 6.380	%		2025 - 2037		85,000		85,000
Medium Term Note IV		7.500	%		2018		50,000		50,000
Total first mortgage bonds							234,000		234,000
Medium Term Notes – CNG
Medium Term Note Series A		6.85% - 9.10	%		2012 - 2017	$	55,000	$	55,000
Medium Term Note Series B		8.12% - 8.49	%		2014 - 2024		10,000		10,000
Medium Term Note Series C		5.63% - 6.66	%		2035 - 2037		65,000		65,000
Medium Term Note Series D		6.50	%		2013		20,000		-
Total medium-term notes							150,000		130,000
Unsecured pollution control notes, variable – TEN
Industrial Revenue Variable   Rate Demand Bonds		1.465	%		2025 - 2030		-		14,900
							384,000		378,900
Less debt due within one year, included in current liabilities							40,000		-
Total Long-Term Debt						$	344,000	$	378,900

We have no intercompany collateralizations and have no guarantees to affiliates or subsidiaries. Our debt has no guarantees from our parent or any additional credit supports. First mortgage bonds are secured with fixed assets.

At December 31, 2009, long-term debt, including sinking fund obligations (in thousands) that will become due during the next five years is:

2010	2011	2012	2013	2014
$40,000	$30,000	$5,000	$40,000	$5,000

Note 5. Bank Loans and Other Borrowings

SCG and CNG are joint borrowers with the other operating utilities under Iberdrola USA in a revolving credit facility providing maximum individual borrowings of up to $40 million for SCG and $30 million for CNG. Sublimits that total to the aggregate limit apply to each joint borrower and can be altered within the constraints imposed by maximum limits that apply to each joint borrower. Each company pays a facility fee on its current revolver sublimit: 8 basis points annually for SCG and 6 basis points for CNG.

We draw on our credit facilities to finance working capital needs, to temporarily finance certain refundings and for other corporate purposes. SCG had no short-term debt outstanding at December 31, 2009, and $55 million at December 31, 2008. The weighted-average interest rate on SCG’s short-term debt was 0.78% at December 31, 2008. CNG had no short-term debt outstanding at December 31, 2009, and $68 million at December 31, 2008. The weighted-average interest rate on CNG’s short-term debt was 0.7% at December 31, 2008.

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

In the revolving credit facility, each joint borrower covenants not to permit, without the consent of the lender, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 at any time. The facility contains various other covenants, including a restriction on the amount of secured indebtedness each borrower may maintain. Continued unremedied failure to comply with those covenants for five business days after written notice of such failure from the lender constitutes an event of default and would result in acceleration of maturity. At December 31, 2009, the ratio of total indebtedness to total capitalization was 0.31 to 1.00 for SCG and 0.30 to 1.00 for CNG. We are not in default as of December 31, 2009.

SCG and CNG also have an intercompany borrowing agreement with Iberdrola USA that provides financing of up to $100 million for each company. Under the terms of that agreement, which expires in October 2010, we pay the same rate as under Iberdrola USA’s credit facility. Iberdrola USA obtains funding for its own short-term needs and for the temporary needs of its subsidiaries through a separate credit facility providing maximum borrowings of up to $300 million. That credit facility expires in 2012 and requires a fee on undrawn borrowings of 10 basis points. As of December 31, 2009, Iberdrola USA had borrowed $93 million of the $300 million available under its facility.

In its revolving credit facility, Iberdrola USA covenants not to permit, without the consent of the lender, its ratio of consolidated indebtedness to consolidated total capitalization to exceed 0.65 to 1.00 at any time. The facility contains various other covenants, including a restriction on the amount of secured indebtedness Iberdrola USA may maintain. Continued unremedied failure to comply with those covenants for 15 days after written notice of such failure from the lender constitutes an event of default and would result in acceleration of maturity. Iberdrola USA’s ratio of consolidated indebtedness to consolidated total capitalization pursuant to the revolving credit facility was 0.55 to 1.00 at December 31, 2009. Iberdrola USA was not in default as of December 31, 2009.

CNE Energy and TEN are parties with Iberdrola USA’s other nonregulated companies in an intercompany borrowing facility through The Energy Network, Inc. that provides each company with financing of up to $25 million. The Energy Network, Inc., a nonregulated subsidiary of Iberdrola USA, maintains a central pooling of funds to facilitate the intercompany borrowing among Iberdrola USA’s nonregulated companies. Under the terms of the agreement, which expires in October 2018, the interest rate for both companies is the same as Iberdrola USA’s average cost of short-term debt. CNE Energy’s short-term debt outstanding under the agreement was $3.1 million at December 31, 2009, and $4.8 million at December 31, 2008. TEN’s short-term debt outstanding under the agreement was $13 million at December 31, 2009, and $22. 9 million at December 31, 2008. The effective interest rate on both companies’ intercompany short-term debt was 0.47% at December 31, 2009, and 2.13% at December 31, 2008.

On May 10, 2010, CNE Energy’s and TEN’s intercompany borrowing facility with The Energy Network, Inc. was replaced by a cash management agreement between Iberdrola USA Management Corporation (IUMC) and the various nonregulated subsidiaries of Iberdrola USA, including CNE Energy and TEN. In accordance with the agreement IUMC provides cash management and related services under a cash management program for the benefit of the participants. Participants may advance funds to IUMC as administrator. IUMC invests the excess funds of the participants and provides funds to each participant for its expenditures upon the participant’s request. Any amount advanced under the agreement, whether by a participant to IUMC or from IUMC to a participant, is considered a loan directly from the party making the advance (the lender) to the par ty receiving the advance (the borrower). The borrower pays

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

interest to the lender on a net cumulative daily balance. Loan amounts are to be repaid upon demand. All amounts advanced, plus accrued but unpaid interest, are to be remitted to the lender. Each participant receives interest on any amounts advanced by the participant to IUMC and pays interest on any funds advanced by IUMC to the participant at IUMC’s short-term borrowing costs.

Note 6. Redeemable Preferred Stock of Subsidiary, Noncontrolling Interests

The redeemable preferred stock of subsidiary are noncontrolling interests because they contain a feature that allows the holders to elect a majority of the subsidiary’s board of directors if preferred stock dividends are in default in an amount equivalent to four full quarterly dividends. Such a potential redemption-triggering event is not solely within the control of the subsidiary.

At December 31, 2009 and 2008, our consolidated redeemable preferred stock, noncontrolling interests was:

			Redemption		Shares		Amount
Subsidiary	Par Value		Price		Authorized and		(Thousands)
and Series	per Share		per Share		Outstanding(1)		2009		2008
CNG, 6.00%	$	100	$	110.00		4,104	$	410	$	410
CNG, 8.00% Noncallable	$	3.125		-		108,706		340		340
Total							$	750	$	750

(1) At December 31, 2009, CNG had 775,609 shares of $3.125 par value preferred stock and 9,994,964 shares of $100 par value preferred stock authorized but unissued.

Note 7. Commitments and Contingencies

Capital spending: We have no material commitments in connection with our capital spending program. Capital spending is expected to be paid for principally with funds generated from debt financing and equity infusion. We plan to invest approximately $280 million in our energy delivery infrastructure during the next five years. The program is subject to periodic review and revision. Our 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 an Infrastructure Replacement Program.

Alleged overcharges by TEN Companies: The state of Connecticut (State) filed suit in February 2007 against Energy East and its subsidiaries TEN, CNG and CTG 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 May 2008 TEN and the State signed a memorandum of understanding (MOU) to allow the parties to finalize an agreement for the State’s purchase of certain heating and cooling equipment that serves certain state buildings (Capitol Area System) at a specified purchase price of $10.6 million, along with other terms specified in the MOU. TEN entered into an Asset Purchase Agreement (Agreement) contemplated in the MOU with the State in November 2008. All lawsuits have been withdrawn with prejudice and mutual releases have been exchanged. The State passed legislation authorizing the Agreement and the sale was completed on June 1, 2009.

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Note 8. Environmental Liability

In the ordinary course of business, we may incur costs to clean up environmental contaminants related to natural gas activity or may incur costs to implement new or modified governmental environmental regulations or requirements. In those instances, we expect that the remediation or implementation costs will be recoverable in rates.

We have identified coal tar residue at three Connecticut sites (two in Bridgeport and one in New Haven) where gas was manufactured in the past. The company received a letter from the Connecticut Department of Environmental Protection (DEP) informing it that the three sites had been entered on the Connecticut inventory of hazardous waste sites.

We entered into a consent order with the DEP with respect to the site located at 39 Pine Street in Bridgeport, Connecticut. Pursuant to the consent order, we agreed to undertake an investigation of the site and its immediate surrounding area to determine potential sources of contamination and to remediate contamination that may be found to have emanated or be emanating from the site as a result of our activities at the site. To date, we have completed Phase I and Phase II of the Part A remediation (relating to the property adjacent to our property) and are awaiting DEP approval to proceed with Part B of the remediation (relating to the containment of contaminated soil and the construction of a cap on our property).

We have incurred in excess of $10 million for pilot studies, design work, remediation activities, containment activities and legal fees associated with the site and the consent order. Some of these costs are currently included in our rate base as capital improvements (a groundwater treatment system), and the remainder of these costs have been deferred and are being amortized at a rate of $500,000 per year pursuant to the settlement in our rate case. We estimate that approximately another $2 million may be spent on the soil containment activities at the site to complete Part B of the remediation. Although we cannot estimate the cost to investigate and remediate the remaining MGP sites, or whether any of the costs associated with these three sites will be recoverable in our rates, we do not expect that such costs will have a material advers e effect on our results of operations or financial condition.

In August 2008 a release into navigable waters occurred at another of our MGP sites at Chapel Street in New Haven, Connecticut. The release was caused by a breach of the storm sewer system at the site. We immediately began to replace the storm sewer system and implement a recovery system to capture contaminants that had infiltrated the water being discharged from the site. We commenced this voluntary action at the suggestion of and with the cooperation of the DEP, local municipal officials, EPA and the Coast Guard. We updated our existing site assessment for the property to reflect those developments and recharacterize the site. We expect to continue with this voluntary recovery process with the goal of continued containment of certain contaminants in the groundwater at the site.

The liability related to our voluntary efforts is approximately $750,000. If, however, the DEP changes its approach or strategy with regard to this property and the DEP were to take a more aggressive approach to the remediation of the site, the cost of containment and remediation would be difficult to estimate, but could be significant. We would expect to recover those costs in rates.

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Note 9. Fair Value of Financial Instruments and Fair Value Measurements

The carrying amounts and estimated fair values of our financial instruments are shown in the following table.

December 31,	2009				2008
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
(Thousands)
First mortgage bonds	$	234,000	$	236,427	$	234,000	$	232,890
Various medium term notes	$	150,000	$	155,942	$	130,000	$	124,972
Pollution control notes, variable		-		-	$	14,900	$	14,900
Total	$	384,000	$	392,369	$	378,900	$	372,762

The carrying amounts for cash and cash equivalents, accounts receivable and notes payable approximate their estimated fair values.

We value all fixed rate long-term debt, whether unsecured or secured by a first mortgage lien, taxable or tax-exempt, by assigning a market-based yield for each security and then deriving the price from the yield. Market-based yields are determined by observing secondary market trading levels for debt of similar maturity, rating, tax and structural characteristics. We value all variable rate debt at par because it approximates fair value.

Assets and liabilities measured at fair value on a recurring basis

	Fair Value Measurements at December 31, Using
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(Thousands)
2009
Assets
Noncurrent investments   available for sale	$	13,445	$	13,445		-		-
Derivatives		306		-		-	$	306
Total	$	13,751	$	13,445		-	$	306
2008
Assets
Noncurrent investments   available for sale	$	17,785	$	17,785		-		-
Derivative		316		-			$	316
Total	$	18,101	$	17,785		-	$	316
Liabilities
Derivatives	$	652		-		-	$	652
Total	$	652		-		-	$	652

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

Fleet fuel derivatives are included in Level 3 of the fair value hierarchy due to the fact that a proprietary calculation (unobservable to the market) is used to arrive at the valuation. The fair

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

value of fleet fuel derivative contracts is determined by comparing the initial cost of the derivative contracts to the exchange-based settlement price as described in New York Mercantile Exchange Rulebook Chapter 6 Section 6.51(a) adjusted by a calculated rolling three-year locational basis derived from actual company purchases of fleet fuel within a particular fleet fueling location.

Instruments measured at fair value on a recurring basis using significant

unobservable inputs

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Successor						Predecessor
Derivatives, Net	Year Ended  December  31, 2009			Period  September 17,  to December  31, 2008			Period  January 1, to September  16, 2008
(Thousands)
Beginning balance	$	(336	)	$	(38	)	$	562
Total (losses) (realized/unrealized)
Included in earnings		471			(246	)		(13,177	)
Included in other comprehensive income		171			(52	)		(412	)
Transfers into Level 3		-			-			12,989
Ending balance	$	306		$	(336	)	$	(38	)
Total losses for the period included in earnings attributable to the change in unrealized gains relating to assets still held at December 31	$	19		$	(341	)	$	(147	)

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:

	Other operating expense			Other Deductions
(Thousands)
Total (losses) included in earnings for:
Successor
Year ended December 31, 2009	$	471			-
Period September 17, to December 31, 2008		(93	)	$	(153	)
Predecessor
January 1, to September 16, 2008	$	(190	)	$	(12,987	)

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Note 10. Accumulated Other Comprehensive Income (Loss)

		Predecessor														Successor
		Balance January 1, 2007			2007 Change		Balance December 31, 2007			January 1, to September 16, 2008 Change			Balance September 16, 2008			September 17, to December 31, 2008 Change			Balance December 31, 2008			2009 Change		Balance December 31, 2009
(Thousands)
Net unrealized holding gains (losses) on investments, net of income tax benefit (expense) of $(162) for 2007, $786 for the period ended September 16, 2008, $710 for the period ended December 31, 2008, and $(737) for 2009	$	864		$	245	$	1,109		$	(1,186	)	$	(77	)	$	(1,070	)	$	(1,147	)	$	1,111	$	(36	)
Amortization of pension costs for   nonqualified plans, net of income tax   (expense) benefit of $(540) for 2007, $(248) for the period ended September 16, 2008, $20 for the period ended December 31, 2008, and $(206) for 2009		(1,644	)		813		(831	)		375			(456	)		44			(412	)		238		(174	)
Unrealized (losses) gains on derivatives qualified as hedges, net of income tax benefit (expense) of $(40) for 2007, $86 for the period ended September 16, 2008, $230 for the period ended December 31, 2008, and $(89) for 2009					61					(130	)					(346	)					135
Reclassification adjustment for derivative losses included in net income, net of income tax (benefit) of $(22) for 2007, $11 for the period ended September 16, 2008, $(29) for the period ended December 31, 2008, and $(187) for 2009					34					(15	)					42						282
Net unrealized gains (losses) on derivatives qualified as hedges		(37	)		95		58			(145	)		(87	)		(304	)		(391	)		417		26
Accumulated Other Comprehensive Income (Loss)	$	(817	)	$	1,153	$	336		$	(956	)	$	(620	)	$	(1,330	)	$	(1,950	)	$	1,766	$	(184	)

No Accumulated Other Comprehensive Income (Loss) is attributable to the noncontrolling interests for any of the above periods.

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

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 postretirement health care benefit plans covering substantially all of our employees. The health care plans are contributory with participants' contributions adjusted annually.

Pension Benefits

				Successor			Predecessor
Obligations and funded status:	Year Ended  December  31, 2009			Period  September 17, to  December 31,  2008			Period  January 1, to  September  16, 2008
(Thousands)
Change in benefit obligation
Benefit obligation at beginning of period	$	293,101		$	255,075		$	285,699
Service cost		4,670			972			3,628
Interest cost		17,710			4,344			12,752
Plan amendments		125			-			4
Actuarial loss (gain)		8,631			36,347			(36,094	)
Benefits paid		(14,898	)		(3,638	)		(10,914	)
Benefit obligation at end of period	$	309,339		$	293,100		$	255,075
Change in plan assets
Fair value of plan assets at beginning   of period	$	189,044		$	224,120		$	282,978
Actual return on plan assets		38,155			(31,439	)		(47,944	)
Benefits paid		(14,898	)		(3,638	)		(10,914	)
Fair value of plan assets at end of period	$	212,301		$	189,043		$	224,120
Funded status at end of period	$	(97,038	)	$	(104,057	)	$	(30,955	)

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Postretirement Benefits 

	Successor						Predecessor
Obligations and funded status:	Year Ended December 31, 2009			Period September 17, to December 31, 2008			Period January 1, to September 16, 2008
(Thousands)
Change in benefit obligation
Benefit obligation at beginning of period	$	55,344		$	52,047		$	56,859
Service cost		570			149			446
Interest cost		3,274			845			2,536
Plan participants’ contributions		1,855			351			1,052
Plan amendments		-			8			24
Actuarial loss (gain)		2,373			3,337			(4,691	)
Benefits paid		(5,803	)		(1,521	)		(4,562	)
Federal subsidy on benefits paid		308			128			383
Benefit obligation at end of period	$	57,921		$	55,344		$	52,047
Change in plan assets
Fair value of plan assets at beginning   of period	$	15,840		$	18,779		$	24,020
Actual return on plan assets		2,226			(1,820	)		(1,884	)
Contributions		4,700			-			-
Plan participants contributions		1,403			245			736
Benefits paid		(5,320	)		(1,364	)		(4,093	)
Fair value of plan assets at end of period	$	18,849		$	15,840		$	18,779
Funded status at end of period	$	(39,072	)	$	(39,504	)	$	(33,268	)

Amounts recognized on the balance sheet	Pension Benefits						Postretirement Benefits
December 31,	2009			2008			2009			2008
Noncurrent liabilities	$	(97,038	)	$	(104,057	)	$	(39,072	)	$	(39,504	)

We have determined that we are allowed to defer as regulatory assets or regulatory liabilities items that would otherwise be recorded in accumulated other comprehensive income pursuant to the accounting requirements concerning defined benefits and other postretirement plans. Amounts recognized as regulatory assets or regulatory liabilities consist of:

	Pension Benefits				Postretirement Benefits
December 31,	2009		2008		2009			2008
(Thousands)
Net loss (gain)	$	151,606	$	165,796	$	9,041		$	8,726
Prior service cost (credit)	$	997	$	1,391	$	(301	)	$	(165	)

Our accumulated benefit obligation for defined benefit pension plans at December 31 was $286 million for 2009 and $270 million for 2008.

Our postretirement benefits were partially funded at December 31, 2009 and 2008. The accumulated benefit obligation and projected benefit obligation exceeded the fair value of pension plan assets as of December 31, 2009 and 2008. The following table shows the

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

aggregate projected and accumulated benefit obligations and the fair value of plan assets for the underfunded pension plans.

December 31		2009		2008
(Thousands)
Projected benefit obligation	$	309,339	$	293,100
Accumulated benefit obligation	$	285,767	$	270,147
Fair value of plan assets	$	212,301	$	189,043

Components of net periodic benefit cost and other amounts

recognized in regulatory assets and regulatory liabilities:

Pension Benefits

	Successor						Predecessor
	Year Ended  December 31, 2009			Period  September 17, to  December 31,  2008			Period  January 1, to  September 16,  2008			Year Ended  December  31, 2007
(Thousands)
Net periodic benefit cost
Service cost	$	4,670		$	972		$	3,628		$	4,880
Interest cost		17,710			4,344			12,752			16,428
Expected return on plan assets		(21,838	)		(5,806	)		(17,945	)		(22,822	)
Amortization of prior service cost		519			131			388			591
Amortization of net loss (gain)		6,503			346			2,523			4,677
Net periodic benefit cost	$	7,564		$	(13	)	$	1,346		$	3,754
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities
Net (gain) loss	$	(7,686	)	$	74,969		$	28,418		$	(14,503	)
Amortization of net (loss) gain		(6,503	)		(346	)		(2,523	)		(4,677	)
Prior service cost		125			-			4			25
Amortization of prior service (cost)		(519	)		(131	)		(388	)		(591	)
Total recognized in   regulatory assets (liabilities)	$	(14,583	)	$	74,492		$	25,511		$	(19,746	)
Total recognized in net   periodic benefit cost and   regulatory assets (liabilities)	$	(7,019	)	$	74,479		$	26,857		$	(15,993	)

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Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Postretirement Benefits

	Successor						Predecessor
	Year Ended  December  31, 2009			Period  September 17, to  December 31,  2008			Period  January 1, to  September 16,  2008			Year Ended  December  31, 2007
(Thousands)
Net periodic benefit cost
Service cost	$	569		$	108		$	487		$	643
Interest cost		3,274			898			2,483			3,254
Expected return on plan assets		(897	)		(297	)		(1,113	)		(1,601	)
Amortization of prior service cost		137			40			96			128
Amortization of net loss (gain)		728			135			300			438
Net periodic benefit cost	$	3,811		$	884		$	2,253		$	2,862
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities
Net (gain) loss	$	1,044		$	4,979		$	(1,219	)	$	(859	)
Amortization of net (loss) gain		(728	)		(163	)		(272	)		(438	)
Prior service cost		-			-			33			-
Amortization of prior service (cost)		(137	)		(40	)		(96	)		(128	)
Total recognized in   regulatory assets (liabilities)	$	179		$	4,776		$	(1,554	)	$	(1,425	)
Total recognized in net   periodic benefit cost and   regulatory assets (liabilities)	$	3,990		$	5,660		$	699		$	1,437

We include the net periodic benefit cost in other operating expenses. The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. The amount of postretirement benefit cost deferred at December 31 was $12 million for 2009 and $13 million for 2008. We expect to recover any deferred postretirement costs by 2012. We are amortizing over 20 years the transition obligation for postretirement benefits that resulted from our adoption in 1992 of the accounting requirements concerning employers’ accounting for postretirement benefits other than pensions.

Amounts expected to be amortized from regulatory assets or regulatory liabilities into net periodic benefit cost for the fiscal year ended December 31, 2010	Pension Benefits		Postretirement Benefits
(Thousands)
Estimated net loss	$	8,575	$	706
Estimated prior service cost	$	339	$	(24	)

We expect that no pension benefit or postretirement benefit plan assets will be returned to us during the fiscal year ending December 31, 2010.

Cash Flows

Contributions: In accordance with our funding policy we make annual contributions of not less than the minimum required by applicable regulations. We expect to contribute approximately $1 million to our pension benefit plans and $2.5 million to our other postretirement benefit plans in 2010.

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Estimated future benefit payments: Our expected benefit payments and expected Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) subsidy receipts, which reflect expected future service, as appropriate, are as follows:

	Pension Benefits		Postretirement Benefits		Medicare Act Subsidy Receipts
(Thousands)
2010	$	15,154	$	5,195	$	464
2011	$	16,024	$	5,329	$	487
2012	$	16,964	$	5,397	$	523
2013	$	17,859	$	5,449	$	558
2014	$	18,543	$	5,482	$	591
2015 – 2019	$	103,558	$	26,344	$	3,343

	Pension Benefits						Postretirement Benefits
Weighted-average assumptions used to determine benefit obligations at December 31,	2009			2008			2009			2008
Discount rate		5.80	%		6.10	%		5.80	%		6.10	%
Rate of compensation increase		4.00	%		4.00	%		N/A			N/A

As of December 31, 2009, we decreased our discount rate from 6.10% to 5.80%. The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rate by developing a yield curve derived from a portfolio of high grade noncallable bonds that closely matches the duration of the expected cash flows of our benefit obligations.

Weighted-average assumptions used to determine net periodic benefit cost years ended December 31,	Pension Benefits			Postretirement Benefits
	2009	2008	2007	2009	2008	2007
Discount rate	6.10%	6.00%	5.75%	6.10%	6.00%	5.75%
Expected return on plan assets	8.75%	8.75%	8.75%	8.00%	8.00%	8.00%
Rate of compensation increase	4.00%	4.00%	4.00%	N/A	N/A	N/A

In September 2008 our pension benefit obligations and post retirement benefit obligations were remeasured using a discount rate of 7.0%. This rate was also used to calculate net periodic benefit cost for the period from September 17, to December 31, 2008. We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations and the effect of rebalancing of plan assets discussed below. That analysis considered current capital market conditions and projected conditions. We amortize unrecognized actuarial gains and losses using the standard amortization methodology, under which amounts in excess of 10% of the greater of the projected benefit obligation or market-related value are amortized over the plan participants’ av erage remaining service to retirement.

Assumed health care cost trend rates to determine benefit obligations at December 31	2009			2008			2007
Health care cost trend rate assumed for next year		8.0	%		8.0	%		8.0	%
Rate to which cost trend rate is assumed to decline (the ultimate rate trend rate)		4.5	%		5.0	%		5.0	%
Year that the rate reaches the ultimate trend rate		2028			2014			2014

31

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Assumed health care cost trend rates have a significant effect on the amount reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase		1% Decrease
(Thousands)
Effect on total of service and interest cost	$	127	$	(103	)
Effect on postretirement benefit obligation	$	1,999	$	(1,714	)

Plan assets: Iberdrola USA’s pension benefits plan assets are held in a master trust providing for a single trustee/custodian, a uniform investment manager lineup, and an efficient, cost-effective means of allocating expenses and investment performance to each plan under the master trust. Iberdrola USA’s primary investment objective is to ensure that current and future benefits obligations are adequately funded and with volatility commensurate with its tolerance for risk. Preservation of capital and achievement of sufficient total return to fund accrued and future benefits obligations are of highest concern. Iberdrola USA’s primary means for achieving capital preservation is through diversif ication of the trust’s investments while avoiding significant concentrations of risk in any one area of the securities markets. Within each asset group, further diversification is achieved through utilizing multiple asset managers and systematic allocation to various asset classes; providing broad exposure to different segments of the equity, fixed-income and alternative investment markets.

Iberdrola USA’s asset allocation policy is the most important consideration in achieving its objective of superior investment returns while minimizing risk. Iberdrola USA has established a target asset allocation policy within allowable ranges for its pension benefits plan assets of 58% equity securities, 27% fixed income and 15% for all other types of investments. The target allocations within allowable ranges are further diversified into 30% large cap domestic equities, 10% medium and small cap domestic equities and 18% international equity securities. Fixed income investment targets and ranges are segregated into core fixed income at 5%, long dated corporate securities 6%, annuity contracts 13% and high yield fixed income 3%. All fixed income investments are in domestic securities. Other alternative investment targets are 5% each for real estate, absolute return and strategic markets. Systematic rebalancing within the target ranges, should any asset categories drift outside their specified ranges, increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk.

32

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

The fair values of the Iberdrola USA consolidated pension benefits plan assets at December 31, 2009, by asset category are shown in the following table. We owned approximately 10% of the total consolidated assets.

			Fair Value Measurements at December 31, 2009, Using
Asset Category	Total		Quoted Prices  in Active  Markets for  Identical Assets  (Level 1)		Significant  Observable  Inputs  (Level 2)		Significant  Unobservable  Inputs  (Level 3)
(Thousands)
Cash and cash equivalents	$	38,248	$	927	$	37,321		-
U.S. government securities		49,619		49,619		-		-
Common stocks		1,000,311		997,495		2,816		-
Registered investment companies		119,155		119,155		-		-
Corporate bonds		364,243		-		364,243		-
Preferred stocks		6,916		6,916		-		-
Common/collective trusts		358,201		-		62,557	$	295,644
Partnership/joint venture interests		93,269		-		-		93,269
Real estate investments		40,618		-		-		40,618
Other investments, principally   annuity and fixed income		183,173		20,784		31,265		131,124
Total	$	2,253,753	$	1,194,896	$	498,202	$	560,655

Valuation techniques: Iberdrola USA values its pension benefits plan assets as follows:

·   Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings.

·   U.S. government securities, Common stocks and Registered investment companies - at the closing price reported in the active market in which the security is traded.

·   Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings.

·   Preferred stocks – at the closing price reported in the active market in which the individual investment is traded.

·   Common/collective trusts and Partnership/joint ventures – using the Net Asset Value (NAV) provided by the administrator of the fund. The NAV is based on the value of the underlying assets owned by the fund, minus its liabilities, and then divided by the number of shares outstanding. The NAV is classified as Level 2 if the plan has the ability to redeem the investment with the investee at NAV per share at the measurement date. Redemption restrictions or adjustments to NAV based on unobservable inputs result in the fair value measurement being classified as a Level 3 measurement if those inputs are significant to the overall fair value measurement.

·   Real estate investments – based on a discounted cash flow approach that includes the projected future rental receipts, expenses and residual values because the highest and best use of the real estate from a market participant view is as rental property.

·   Other investments, principally annuity and fixed income - Level 1: at the closing price reported in the active market in which the individual investment is traded. Level 2: based on yields currently available on comparable securities of issuers with similar credit ratings. Level 3: when quoted prices are not available for identical or similar instruments, under a discounted cash flows approach that maximizes observable inputs such as current yields of similar instruments but includes adjustments for certain risks that may not be observable such as credit and liquidity risks.

33

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
(Thousands)	Corporate   Bonds			Common/  Collective   Trusts			Partner-  ship/  Joint   Venture   Interests			Real  Estate   Invest-  ments			Other  Invest- ments			Total
Balance, December 31, 2008	$	112		$	432,918		$	106,819		$	58,687		$	156,149		$	754,685
Actual return on plan assets:
Relating to assets still held at the      reporting date		-			2,557			2,565			-			-			5,122
Relating to assets sold during      the year		-			112,364			3,869			(19,345	)		-			96,888
Purchases, sales and settlements		(112	)		(252,195	)		(19,984	)		1,276			(25,025	)		(296,040	)
Transfers into and/or out of Level 3		-			-			-			-			-			-
Balance, December 31, 2009		-		$	295,644		$	93,269		$	40,618		$	131,124		$	560,655

Iberdrola USA’s postretirement benefits plan assets are held with two trustees in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements and are invested among and within various asset classes in order to achieve sufficient diversification in accordance with its risk tolerance. This is achieved for its postretirement benefits plan assets through the utilization of multiple institutional mutual and money market funds, providing exposure to different segments of the fixed income, equity and short-term cash markets. Approximately 20% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes. The remainder is invested in arrangements subject to income taxes.

Iberdrola USA has established a target asset allocation policy within allowable ranges for its postretirement benefits plan assets of 56% equity securities, 37% fixed income and 7% for all other types of investments. The target allocations within allowable ranges are further diversified into 30% large cap domestic equities, 7% medium and small cap domestic equities, 13% international developed market and 6% emerging market equity securities. Fixed income investment targets and ranges are segregated into core fixed income at 30%, global high yield fixed income 4% and international developed market debt 3%. Other, alternative investment targets are 4% for real estate and 3% absolute return. Systematic rebalancing within target ranges, should any asset categories drift outside their specified ranges, increases the probability that the annual ized return on the investments will be enhanced, while realizing lower overall risk.

34

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

The fair values of the Iberdrola USA consolidated other postretirement benefits plan assets at December 31, 2009, by asset category are shown in the following table. We owned approximately 13% of the total consolidated assets.

			Fair Value Measurements at December 31, 2009, Using
Asset Category	Total		Quoted Prices  in Active  Markets for  Identical Assets  (Level 1)		Significant  Observable  Inputs  (Level 2)		Significant  Unobservable  Inputs  (Level 3)
(Thousands)
Money market funds	$	4,214	$	4,214		-		-
Mutual funds, fixed		51,061		51,061		-		-
Mutual funds, equity		82,089		82,089		-		-
Other investments		3,109		1,865	$	774	$	470
Total assets measured at     fair value	$	140,473	$	139,229	$	774	$	470
Whole life insurance contract		5,836
Total postretirement benefits     plan assets	$	146,309

Valuation techniques: Iberdrola USA values its postretirement benefits plan assets as follows:

·   Money market funds and Mutual funds, fixed and equity – based upon quoted market prices, which represent the NAV of the shares held.

·   Other investments – these are primarily 401(h) investments that are an allocation of pension Master Trust investments.

The whole life insurance contract is presented at the contract value, which is not a fair value measurement.

Diversified equity securities did not include any Iberdrola common stock at December 31, 2009.

Note 12. Investment in Wind Farms

In April 2009 CEC, through its subsidiary CNE Energy, acquired an interest in various wind farms owned by Aeolus Wind Power V LLC (Aeolus V) in exchange for $305.4 million in cash. CNE Energy obtained those funds from an equity infusion of $305.4 million from CEC. CNE Energy purchased its membership interest in Aeolus V from PPM Wind Energy LLC (PPM), an affiliate of Iberdrola USA, which contributed its 100% ownership of the wind farms to Aeolus V.

The main characteristics of the investment are as follows:

·   PPM retains day-to-day management of the wind farms. Defined major decisions require consent from CNE Energy.

·   As a minority shareholder, CNE Energy has the right to a substantial portion of the profits and tax credits generated by the wind farms up to the return level established at the beginning of the investment contract.

·   CNE Energy initially holds a 50% interest in Aeolus V until it achieves a stipulated 7.5% return, after which it is entitled to maintain a 5% ownership interest.

·   PPM has the option to purchase, at fair market value, CNE Energy’s remaining residual equity interest, which is exercisable after CNE Energy achieves its agreed upon return.

·   Whether or not CNE Energy obtains the agreed upon return depends on the economic performance of the wind farms. While PPM is bound to operate and maintain the facilities in

35

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

an efficient manner and maintain appropriate insurance, it is not obligated to deliver cash to CNE Energy over and above the aforementioned profits and tax credits.

CNE Energy uses an equity method referred to as Hypothetical Liquidation at Book Value (HLBV) to account for its investment in Aeolus V. The application of that method results in CNE Energy recording a gain or loss on its investment based on the cash implications of a liquidation at book value, with a corresponding adjustment to the investment account. In addition, the HLBV method requires the tax effects related to Production Tax Credits and taxable income (loss) to be recorded in income taxes on the income statement. Finally, the HLBV method requires a credit to accumulated deferred income taxes on the balance sheet and a debit to income taxes on the income statement for an amount representing the statutory rate applied to the difference between the tax basis and the book basis of the investment.

The following table shows the effects of the investment on our consolidated income statement and balance sheet:

Income statement for the year ended December 31,	2009
(Thousands)
Other income (loss), earnings from equity investment	$	(579	)
Income tax benefit		14,746
Total income statement benefit	$	14,167

Balance sheet at December 31,
(Thousands)
Investment in wind farms	$	304,821
Deferred tax liabilities, noncurrent		(32,964	)
Prepaid income taxes	$	47,709

The following table provides summary financial information for Aeolus V:

Income statement for April 27 to December 31,	2009
(Thousands)
Revenues, including PTCs	$	49,614
Operating income		12,146
Net (loss), including PTCs	$	(2,648	)

Balance sheet at December 31,
(Thousands)
Total Assets	$	688,528
Total Equity	$	673,462

36

Notes to Combined Financial Statements

Connecticut Energy Corporation and CTG Resources, Inc.

Note 13. Segment Information

Selected financial information for our operating segments is presented in the table below. Our natural gas delivery segment consists of our regulated transportation, storage and distribution operations in Connecticut. We measure segment profitability based on net income. Eliminations and other includes primarily our intersegment and intercompany eliminations

	Natural  Gas  Delivery		CNE  Energy			TEN		Eliminations  and Other			Total
(Thousands)
Year Ended December 31, 2009
Operating Revenues	$	677,981	$	12,562		$	32,953	$	(9,795	)	$	713,701
Depreciation and Amortization	$	39,682	$	8,681		$	2,698		-		$	51,061
Interest Charges, Net	$	31,470	$	31		$	364		-		$	31,865
Income Taxes (Benefits)	$	7	$	(16,141	)	$	3,974		-		$	(12,160	)
Net Income Attributable to   CEC and CTG	$	22,655	$	12,340		$	5,388	$	(3,463	)	$	36,920
Total Assets	$	2,036,072	$	353,736		$	71,958	$	(2,976	)	$	2,458,790
Period September 17, to   December 31, 2008
Operating Revenues	$	262,029	$	3,288		$	10,079	$	(2,345	)	$	273,051
Depreciation and Amortization	$	11,681	$	459		$	816		-		$	12,956
Interest Charges, Net	$	8,943	$	53		$	581		-		$	9,577
Income Taxes (Benefits)	$	2,865	$	416		$	1,189		-		$	4,470
Net Income Attributable to   CEC and CTG	$	6,531	$	628		$	1,823	$	321		$	9,303
Total Assets	$	2,167,106	$	51,466		$	112,368	$	(27,759	)	$	2,303,181
Period January 1, to   September 16, 2008
Operating Revenues	$	614,486	$	9,663		$	33,738	$	(6,833	)	$	651,054
Depreciation and Amortization	$	27,174	$	1,283		$	2,740		-		$	31,197
Interest Charges, Net	$	21,666	$	114		$	1,722		-		$	23,502
Income Taxes (Benefits)	$	9,541	$	1,203		$	763		-		$	11,507
Net Income Attributable to   CEC and CTG	$	28,891	$	1,815		$	1,535	$	1,074		$	33,315
Total Assets	$	2,268,982	$	52,346		$	111,728	$	(29,123	)	$	2,403,933
Year Ended December 31, 2007
Operating Revenues	$	795,272	$	13,133		$	44,314	$	(9,360	)	$	843,359
Depreciation and Amortization	$	38,686	$	1,472		$	4,624		-		$	44,782
Interest Charges, Net	$	31,200		-		$	2,732		-		$	33,932
Income Taxes (Benefits)	$	22,131	$	1,671		$	2,626		-		$	26,428
Net IncomeAttributable to   CEC and CTG	$	47,757	$	2,519		$	4,512	$	(140	)	$	54,648
Total Assets	$	1,991,739	$	43,127		$	121,860	$	(36,763	)	$	2,119,963

37