8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 or 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported):  June 24, 2011

(Exact name of registrant as specified in its charter)

Connecticut	1-15052	06-1541045
(State or other jurisdiction	(Commission	(IRS Employer
of Incorporation)	File Number)	Identification No.)
157 Church Street, New Haven, Connecticut		06506
(Address of principal executive offices)		(Zip Code)
Registrant's Telephone Number,
Including Area Code		(203) 499-2000

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

£      Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

£      Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

£      Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

£       Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01 Regulation FD Disclosure.

On June 24, 2011, UIL Holdings Corporation (the “Registrant”) disclosed the information, contained in the exhibits attached hereto, relating to its wholly owned utility subsidiaries, The United Illuminating Company, Connecticut Natural Gas Corporation, The Southern Connecticut Gas Company and The Berkshire Gas Company.

The information in this Form 8-K shall not be deemed to be “filed” for the purposes of Section 18 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of such section, nor shall such information be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01 Financial Statements and Exhibits.

(d)	Exhibits – The following exhibit is furnished as part of this report:
99.1	The United Illuminating Company Audited Financial Statements as of and for the years ended December 31, 2010 and 2009.
99.2	Connecticut Natural Gas Corporation Financial Statements for the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor).
99.3	The Southern Connecticut Gas Company Financial Statements for the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor).
99.4	The Berkshire Gas Company Financial Statements for the Period from November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor).
99.5	Financial Statements of The United Illuminating Company as of and for the three months ended March 31, 2011 and 2010 (Unaudited).
99.6	Connecticut Natural Gas Corporation Financial Statements (Unaudited) for the three months ended March 31, 2011 and 2010.
99.7	The Southern Connecticut Gas Financial Statements (Unaudited) for the three months ended March 31, 2011 and 2010.
99.8	The Berkshire Gas Company Financial Statements (Unaudited) for the three months ended March 31, 2011.

SIGNATURES

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

UIL HOLDINGS CORPORATION

Registrant

Date:  6/24/11	By                /s/ Richard J. Nicholas
	Richard J. Nicholas
	Executive Vice President
	and Chief Financial Officer

Exhibit Index

Exhibit	Description
99.1	The United Illuminating Company Audited Financial Statements as of and for the years ended December 31, 2010 and 2009.
99.2	Connecticut Natural Gas Corporation Financial Statements for the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor).
99.3	The Southern Connecticut Gas Company Financial Statements for the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor).
99.4	The Berkshire Gas Company Financial Statements for the Period from November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor).
99.5	Financial Statements of The United Illuminating Company as of and for the three months ended March 31, 2011 and 2010 (Unaudited).
99.6	Connecticut Natural Gas Corporation Financial Statements (Unaudited) for the three months ended March 31, 2011 and 2010.
99.7	The Southern Connecticut Gas Financial Statements (Unaudited) for the three months ended March 31, 2011 and 2010.
99.8	The Berkshire Gas Company Financial Statements (Unaudited) for the three months ended March 31, 2011.

EX-99.1

EXHIBIT 99.1

THE UNITED ILLUMINATING COMPANY

AUDITED FINANCIAL STATMENTS

AS OF AND FOR THE YEARS ENDED

DECEMBER 31, 2010 AND 2009

TABLE OF CONTENTS

	Page
Report of Independent Auditors	2
Financial Statements:
Statement of Income for the Years Ended December 31, 2010 and 2009	3
Statement of Cash Flows for the Years Ended December 31, 2010 and 2009	4
Balance Sheet as of December 31, 2010 and 2009	5
Statement of Changes in Shareholder’s Equity for the Years Ended December 31, 2010 and 2009	7
Notes to Financial Statements	8

THE UNITED ILLUMINATING COMPANY
STATEMENT OF INCOME
For the Years Ended December 31, 2010, and 2009
(In Thousands)
	2010		2009
Operating Revenues	$	859,547	$	895,681
Operating Expenses
Operation
Purchased power		242,268		333,339
Operation and maintenance		238,345		224,921
Transmission wholesale		72,169		57,012
Depreciation and amortization		108,409		97,966
Taxes - other than income taxes		71,641		60,058
Total Operating Expenses		732,832		773,296
Operating Income		126,715		122,385
Other Income and (Deductions), net (Note H), (Note A)		16,040		5,553
Interest Charges, net
Interest on long-term debt		38,226		33,317
Other interest, net		815		1,219
		39,041		34,536
Amortization of debt expense and redemption premiums		1,532		1,755
Total Interest Charges, net		40,573		36,291
Income Before Income Taxes, Equity Earnings		102,182		91,647
Income Taxes (Note E)		39,708		34,733
Income Before Equity Earnings		62,474		56,914
Income from Equity Investments		1,278		59
Net Income	$	63,752	$	56,973
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

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THE UNITED ILLUMINATING COMPANY
STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2010, and 2009
(Thousands of Dollars)
	2010			2009
Cash Flows From Operating Activities
Net income attributable to UIL Holdings	$	63,752		$	56,973
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization		109,941			99,721
Deferred income taxes		57,308			(7,128	)
Stock-based compensation expense (Note A)		3,144			2,316
Pension expense		27,422			22,313
Undistributed (earnings) losses in equity investments		(1,278	)		(59	)
Other non-cash items, net		2,508			(12,985	)
Changes in:
Utility accounts receivable, net		(12,385	)		982
Unbilled revenues and other accounts receivable		4,986			1,969
Accounts payable		880			(5,750	)
Interest accrued		3,614			1,945
Taxes accrued		(32,508	)		1,229
Accrued liabilities		9,363			7,291
Other assets		(7,266	)		(68	)
Other liabilities		(5,499	)		2,107
Total Adjustments		160,230			113,883
Net Cash provided by Operating Activities		223,982			170,856
Cash Flows from Investing Activities
Related party note receivable (Note H)		(9,750	)		(72,230	)
Plant expenditures including AFUDC debt		(197,405	)		(123,574	)
Investment in GenConn		(6,000	)		-
Changes in restricted cash		1,297			7,379
Other		104			985
Net Cash (used in) Investing Activities		(211,754	)		(187,440	)
Cash Flows from Financing Activities
Issuances of long-term debt		109,550			182,773
Payments on long-term debt		(55,540	)		(51,000	)
Line of credit borrowings (repayments)		-			(148,000	)
Payment of common stock dividend		(57,800	)		(44,900	)
Equity infusion from parent		-			70,000
Inter-company borrowings		-			11,000
Other		(1,569	)		(1,220	)
Net Cash provided by (used in) Financing Activities		(5,359	)		18,653
Unrestricted Cash and Temporary Cash Investments:
Net change for the period		6,869			2,069
Balance at beginning of period		5,348			3,279
Balance at end of period	$	12,217		$	5,348
Cash paid during the period for:
Interest (net of amount capitalized)	$	31,135		$	31,359
Income taxes	$	16,780		$	44,884
Non-cash investing activity:
Plant expenditures included in ending accounts payable	$	53,868		$	30,054
Related party note receivable (Note H)	$	55,540		$	-
Equity investment in Related Party (Note H)	$	(55,540	)	$	-
Non-cash financing activities:
Inter-company repayments	$	-		$	(11,000	)
Equity infusion from parent	$	-		$	11,000
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

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THE UNITED ILLUMINATING COMPANY
BALANCE SHEET
December 31, 2010 and 2009
ASSETS
(In Thousands)
	2010		2009
Current Assets
Unrestricted cash and temporary cash investments	$	12,217	$	5,348
Restricted cash		2,399		3,695
Utility accounts receivable less allowance of $3,600 and $4,500, respectively		93,702		81,861
Other accounts receivable		9,755		8,462
Unbilled revenues		43,399		48,375
Current regulatory assets		45,970		59,040
Materials and supplies, at average cost		4,736		4,553
Deferred income taxes		19,555		4,391
Refundable taxes, net		18,201		-
Prepayments		3,676		3,656
Current portion of derivative assets (Note A), (Note K)		5,700		2,738
Other current assets		133		140
Total Current Assets		259,443		222,259
Other investments
Equity investment in Related Party (Note H)		62,786		1
Other		8,184		7,414
Total Other investments		70,970		7,415
Net Property, Plant and Equipment		1,333,139		1,153,001
Regulatory Assets (future amounts due from customers through the ratemaking process)		601,894		676,428
Deferred Charges and Other Assets
Unamortized debt issuance expenses		7,267		6,496
Related party note receivable (Note H)		61,983		107,773
Other long-term receivable		1,281		1,285
Derivative assets (Note A), (Note K)		28,131		27,956
Other		7,513		450
Total Deferred Charges and Other Assets		106,175		143,960
Total Assets	$	2,371,621	$	2,203,063
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

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THE UNITED ILLUMINATING COMPANY
BALANCE SHEET
December 31, 2010 and 2009
LIABILITIES AND CAPITALIZATION
(In Thousands)
	2010		2009
Current Liabilities
Current portion of long-term debt	$	61,783	$	53,970
Accounts payable		119,229		93,176
Dividends payable		13,300		9,000
Accrued liabilities		42,568		32,837
Current regulatory liabilities		34,635		23,624
Interest accrued		10,910		7,297
Taxes accrued		-		14,307
Current portion of derivative liabilities (Note A), (Note K)		13,231		2,822
Total Current Liabilities		295,656		237,033
Noncurrent Liabilities
Pension accrued		163,055		140,454
Connecticut Yankee contract obligation		17,175		20,694
Other post-retirement benefits accrued		52,014		47,302
Derivative liabilities (Note A), (Note K)		129,560		159,271
Other		19,666		6,052
Total Noncurrent Liabilities		381,470		373,773
Deferred Income Taxes (future tax liabilities owed to taxing authorities)		334,259		278,767
Regulatory Liabilities (future amounts owed to customers through the ratemaking process)		81,353		82,457
Commitments and Contingencies (Note J)
Capitalization (Note B)
Long-term debt, net of unamortized discount and premium		670,460		624,263
Common Stock Equity
Common stock		1		1
Paid-in capital		469,730		469,730
Retained earnings		138,692		137,039
Net Common Stock Equity		608,423		606,770
Total Capitalization		1,278,883		1,231,033
Total Liabilities and Capitalization	$	2,371,621	$	2,203,063
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

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THE UNITED ILLUMINATING COMPANY
Statement of Changes in Shareholder's Equity
December 31, 2010 and 2009
(Thousands of Dollars)
	Common Stock				Paid-in		Retained
	Shares		Amount		Capital		Earnings			Total
Balance as of December 31, 2008		100	$	1	$	387,926	$	126,966		$	514,893
Net income								56,973			56,973
Cash dividends								(46,900	)		(46,900	)
Equity infusion from parent						81,000					81,000
Allocation of benefits - ESOP						804					804
Balance as of December 31, 2009		100	$	1	$	469,730	$	137,039		$	606,770
Net income								63,752			63,752
Cash dividends								(62,099	)		(62,099	)
Balance as of December 31, 2010		100	$	1	$	469,730	$	138,692		$	608,423
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS

(A)  STATEMENT OF ACCOUNTING POLICIES

The United Illuminating Company (UI), a wholly owned subsidiary of UIL Holdings Corporation (UIL Holdings), is a regulated operating electric public utility established in 1899.  It is engaged principally in the purchase, transmission, distribution and sale of electricity for residential, commercial and industrial purposes in a service area of about 335 square miles in the southwestern part of the State of Connecticut.  The population of this area is approximately 736,000, which represents approximately 21% of the population of the State.  The service area, largely urban and suburban, includes the principal cities of Bridgeport (population of approximately 137,000) and New Haven (population of approximately 124,000) and their surrounding areas.  Situated in the service area are retail trade and service centers, as well as large and small industries producing a wide variety of products, including helicopters and other transportation equipment, electrical equipment, chemicals and pharmaceuticals.  As of December 31, 2010, UI had approximately 325,000 customers.  Of UI’s 2010 retail electric revenues, approximately 59.6% were derived from residential sales, 33.7% from commercial sales, 5.3% from industrial sales and 1.4% from street lighting and other sales.  UI’s retail electric revenues vary by season, with the highest revenues typically in the third quarter of the year reflecting seasonal rates, hotter weather and air conditioning use.

UI is also a 50-50 joint venturer, together with NRG Energy, Inc., in GenConn Energy LLC (GenConn), a project selected to build and operate new peaking generation plants to help address Connecticut’s need for power generation during the heaviest load periods.

Accounting Records

The accounting records of UI are maintained in conformity with generally accepted accounting principles in the United States of America (GAAP).

The accounting records for UI are also maintained in accordance with the uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and the Connecticut Department of Public Utility Control (DPUC).

Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to use estimates and assumptions that affect (1) the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and (2) the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Certain immaterial amounts reported in the Balance Sheet and Statement of Cash Flows in previous periods have been reclassified to conform to the current presentation.

UI has evaluated subsequent evens through the date its financial statements were available to be issued, April 6, 2011.

Regulatory Accounting

Generally accepted accounting principles for regulated entities in the United States of America allow UI to give accounting recognition to the actions of regulatory authorities in accordance with the provisions of Accounting Standards Codification (ASC) 980 “Regulated Operations.”  In accordance with ASC 980, UI has deferred recognition of costs (a regulatory asset) or have recognized obligations (a regulatory liability) if it is probable that such costs will be recovered or obligations relieved in the future through the ratemaking process.  UI is allowed to recover all such deferred costs through its regulated rates.  See Note (C), “Regulatory Proceedings,” for a discussion of the recovery of certain deferred costs, as well as a discussion of the regulatory decisions that provide for such recovery.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

In addition to the Regulatory Assets and Liabilities identified on the Balance Sheet and described below, there are other regulatory assets and liabilities such as certain deferred tax liabilities.  UI also has obligations under long-term power contracts, the recovery of which is subject to regulation.  If UI, or a portion of their assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs would be required in the year in which such criteria are no longer met (if such deferred costs are not recoverable in the portion of the business that continues to meet the criteria for application of ASC 980).  UI expects to continue to meet the criteria for application of ASC 980 for the foreseeable future.  If a change in accounting were to occur, it could have a material adverse effect on UI’s earnings and retained earnings in that year and could also have a material adverse effect on UI’s on going financial condition.

UI‘s regulatory assets and liabilities as of December 31, 2010 and 2009 included the following:

	Remaining	December 31,		December 31,
	Period	2010		2009
		(In Thousands)
Regulatory Assets:
Nuclear plant investments – above market	(a)	$	293,388	$	313,833
Income taxes due principally to book-tax differences	(b)		11,910		36,635
Connecticut Yankee	6 years		17,175		20,695
Unamortized redemption costs	12 to 24 years		13,708		14,510
CTA deferral amortization	(a)		-		7,874
Pension and other post-retirement benefit plans	(c)		175,938		169,234
Contracts for differences	(d)		114,662		137,730
Deferred pension and other post-retirement expense	(f)		944		10,232
Distribution retail revenue decoupling	(g)		-		5,286
Excess generation service charge	(e)		8,711		-
Deferred transmission income	(h)		-		8,973
Other	(b)		11,428		10,466
Total regulatory assets			647,864		735,468
Less current portion of regulatory assets			45,970		58,476
Regulatory Assets, Net		$	601,894	$	676,992
Regulatory Liabilities:
Accumulated deferred investment tax credits	33 years	$	4,905	$	5,051
Deferred gain on sale of property	(a)		37,798		37,798
Middletown/Norwalk local transmission network service collections	41 years		23,121		23,695
Pension and other post-retirement benefit plans	4 to 12 years		3,016		-
Excess generation service charge	(e)		-		19,506
Asset removal costs	(b)		109		1,993
Distribution retail revenue decoupling	(g)		756		-
Deferred transmission expense	(h)		27,036		-
Other	(b)		19,247		18,038
Total regulatory liabilities			115,988		106,081
Less current portion of regulatory liabilities			34,635		23,624
Regulatory Liabilities, Net		$	81,353	$	82,457

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

(a) Asset/Liability relates to the Competitive Transition Assessment (CTA).  CTA deferral amortization completed during the 2nd quarter of 2010.  Total CTA costs recovery is currently projected to be completed in 2015, with stranded cost amortization expected to end in 2013.

(b) Amortization period and/or balance varies depending on the nature, cost of removal and/or remaining life of the underlying assets/liabilities.

(c) Asset life is dependent upon timing of final pension plan distribution; balance is recalculated each year in accordance with ASC 715 "Compensation-Retirement Benefits" (Note G).

(d) Asset life is equal to delivery term of related contracts (which vary from approximately 9 - 16 years); balance fluctuates based upon quarterly market analysis performed on the related derivatives (Note K).

(e) Working capital allowance for generation service charge; this amount fluctuates based upon cash inflows and outflows in a given period.

(f) Regulatory asset established for $10.2 million of 2009 pension and OPEB expense which will be recovered in the 2010 rate year.

(g) Regulatory asset or liability relating to revenue decoupling; majority of 2009 decoupling recovered in January 2010 with remaining balance to be recovered through September 2011; 2010 decoupling ratemaking treatment to be determined by the DPUC in 2011.

(h) Regulatory asset or liability which defers transmission income or expense and fluctuates based upon actual revenues and revenue requirements.

Derivatives

UI is party to contracts and is involved in transactions that have been determined to be derivatives, which are discussed below.

The fair value of the gross derivative assets and liabilities as of December 31, 2010 and 2009 were as follows:

	December 31, 2010
	(In Thousands)
			Deferred Charges		Current		Noncurrent
	Current Assets		and Other Assets		Liabilities		Liabilities
Derivative assets/(liabilities), gross	$	5,700	$	28,131	$	13,231	$	129,560
	December 31, 2009
	(In Thousands)
			Deferred Charges		Current		Noncurrent
	Current Assets		and Other Assets		Liabilities		Liabilities
Derivative assets/(liabilities), gross	$	2,738	$	27,956	$	2,822	$	159,271

Contracts for Differences (CfDs)

Pursuant to Connecticut’s 2005 Energy Independence Act (EIA), the DPUC initiated a process to solicit bids to create new or incremental capacity resources in order to reduce federally mandated congestion charges, and selected four new capacity resources.  To facilitate the transactions between selected capacity resources and Connecticut electric customers, and provide the commitment necessary for owners of these resources to obtain necessary financing, the DPUC required that UI and Connecticut Light and Power (CL&P) execute long-term contracts with the selected resources.  In August 2007, the DPUC approved four CfDs, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price.  As directed by the DPUC, UI executed two of the contracts and CL&P executed the other two contracts.  The cost of the contracts will be paid by customers and will be subject to a cost-sharing agreement whereby approximately 20% of the cost is borne by UI customers and approximately 80% by CL&P customers.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

The DPUC has determined that costs associated with these CfDs will be recoverable by UI and CL&P, and in accordance with ASC 980 “Regulated Operations”, UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability).  The CfDs are marked-to-market in accordance with ASC 815.  For those CfDs signed by CL&P, UI records its approximate 20% portion of CL&P’s derivative, pursuant to the sharing agreement noted above.  As of December 31, 2010, UI has recorded a gross derivative asset of $33.8 million ($5.7 million related to its portion of CL&P’s derivative assets), a regulatory asset of $114.7 million, a gross derivative liability of $142.8 million ($107.6 million related to its portion of CL&P’s derivative liabilities) and a regulatory liability of $5.7 million in the accompanying Balance Sheet.  See Note (K) “Fair Value of Financial Instruments” for additional CfD information.

On February 7, 2010, an explosion occurred at the construction site of the nearly completed 620-megawatt plant being built by Kleen Energy Systems, LLC (Kleen), one of the four capacity resources selected by the DPUC to create new or incremental capacity resources described above.  As noted above, CL&P has executed CfDs with two of the selected projects, including the Kleen project.  The CfD with Kleen is subject to the sharing agreement between UI and CL&P whereby UI pays 20% of the costs and obtains 20% of the benefits of the contract.  Kleen continues to rebuild its facility in the wake of the explosion. On February 11, 2011, in response to a Notice of Request for Information from CL&P, Kleen reported to CL&P that Commercial Operation will not occur on April 19, 2011, as was previously reported, because start-up commissioning and testing have yet to be completed.  Kleen will provide CL&P with a revised schedule when it is completed by its contractor.  The actual commencement date of payments under the CfD will remain subject to uncertainty until Commercial Operation is attained.

During 2010, UI adjusted a probability assumption in its expected cash flow analysis based on management’s assessment of the probability of the project reaching commercial operation which significantly reduced the fair value of the related regulatory asset and derivative liability on its Balance Sheet.  A subsequent increase in 2010 to the same assumption resulted in a corresponding increase in the related regulatory asset and derivative liability.  These changes did not have an impact on UI’s Statement of Income.

The unrealized gains and losses from mark-to-market adjustments to derivatives recorded in regulatory assets or regulatory liabilities for the years ended December 31, 2010 and 2009 were as follows:

	Year Ended
	December 31,
	2010			2009
	(In Thousands)
Regulatory Assets - Derivative assets	$	(23,022	)	$	49,421
Regulatory Liabilities - Derivative liabilities	$	584		$	(1,515	)

The adjustments to the expected cash flow analysis, as discussed above, resulted in changes in UI’s projected derivative liability relating to UI’s CfD with Kleen.  The changes in this derivative liability were the primary reasons for the unrealized gain during the year ended December 31, 2010.

Property, Plant and Equipment

The cost of additions to property, plant and equipment and the cost of renewals and betterments are capitalized.  Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC).  The costs of current repairs, major maintenance projects and minor replacements are charged to appropriate operating expense accounts as incurred.  The original cost of utility property, plant and equipment retired or otherwise disposed of and the cost of removal, less salvage, are charged to the accumulated provision for depreciation.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

UI accrues for estimated costs of removal for certain of their plant-in-service.  Such removal costs are included in the approved rates used to depreciate these assets.  At the end of the service life of the applicable assets, the accumulated depreciation in excess of the historical cost of the asset provides for the estimated cost of removal.  In accordance with ASC 410 “Asset Retirement and Environmental Obligations”, the accrued costs of removal have been recorded as a regulatory liability.  Accrued costs of removal as of December 31, 2010 and 2009 were $0.1 million and $2.0 million, respectively.

UI’s property, plant and equipment as of December 31, 2010 and 2009 were comprised as follows:

	2010		2009
	(In Thousands)
Distribution plant	$	777,916	$	699,866
Transmission plant		489,223		493,095
Software		94,025		91,289
Land		33,258		31,514
Other plant		117,710		90,965
Total property, plant & equipment		1,512,132		1,406,729
Less accumulated depreciation		418,779		377,869
		1,093,353		1,028,860
Construction work in progress		239,786		124,141
Net property, plant & equipment	$	1,333,139	$	1,153,001

Allowance for Funds Used During Construction

In accordance with the uniform systems of accounts, the Company capitalizes AFUDC, which represents the approximate cost of debt and equity capital devoted to plant under construction.  The portion of the allowance applicable to borrowed funds and the allowance applicable to equity funds are presented as other income in the Statement of Income.  Although the allowance does not represent current cash income, it has historically been recoverable under the ratemaking process over the service lives of the related properties.  Weighted-average AFUDC rates for 2010 and 2009 were 6.63% and 2.44%, respectively.  The lower rate in 2009 was primarily due to a lower balance of plant under construction as well as a lower average short-term interest rate.

Depreciation

Provisions for depreciation on utility plant for book purposes are computed on a straight-line basis, using estimated service lives.  For utility plant other than software, service lives are determined by independent engineers and subject to review and approval by the DPUC.  Software service life is based upon management’s estimate of useful life.  The aggregate annual provisions for depreciation for 2010 and 2009 were approximately 3.6% and 3.7%, respectively, of the original cost of depreciable property.

Income Taxes

In accordance with ASC 740 “Income Taxes”, UI has provided deferred taxes for all temporary book-tax differences using the liability method.  The liability method requires that deferred tax balances be adjusted to reflect enacted future tax rates that are anticipated to be in effect when the temporary differences reverse.  In accordance with generally accepted accounting principles for regulated industries, UI has established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences.  For ratemaking purposes, UI normalizes all investment tax credits (ITCs) related to recoverable plant investments.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

Under ASC 740, UI may recognize the tax benefit of an uncertain tax position only if management believes it is more likely than not that the tax position will be sustained on examination by the taxing authority based upon the technical merits of the position.  The tax benefits recognized in the financial statements from such a position should be measured based upon the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement.  UI‘s policy is to recognize interest accrued and penalties associated with uncertain tax positions as a component of operating expense.

Revenues

Regulated utility revenues are based on authorized rates applied to each customer.  These retail rates are approved by regulated bodies and can be changed only through formal proceedings.

UI utilizes a customer accounting software package integrated with the network meter reading system to estimate unbilled revenue on a customer-by-customer basis, utilizing actual daily meter readings at the end of each month to calculate consumption and pricing for each customer.  A significant portion of utility retail kilowatt-hour consumption is read through the network meter reading system.  For those customers still requiring manual meter readings, consumption is estimated based upon historical usage and actual pricing for each customer.  Changes in those assumptions could significantly affect the estimates of unbilled revenues.

Cash and Temporary Cash Investments

For cash flow purposes, UI considers all highly liquid debt instruments with a maturity of three months or less at the date of purchase to be cash and temporary cash investments.

Restricted Cash

UI’s restricted cash at December 31, 2010 and 2009 totaled $2.4 million and $3.7 million, respectively, which primarily relates to capital projects, which have been withheld by UI and will remain in place until the verification of fulfillment of contractor obligations.

Equity Investments

UI’s investment in the Connecticut Yankee Atomic Power Company (Connecticut Yankee), a retired nuclear generating company in which UI has a 9.5% stock interest, is accounted for on an equity basis.  This net investment amounted to $0.2 million and $0.3 million at December 31, 2010 and 2009, respectively.  UI received a dividend from Connecticut Yankee in April 2009 and a stock redemption of $0.6 million in October 2009.  The Connecticut Yankee nuclear unit was retired in 1996 and has been decommissioned.  See Note (J), “Commitments and Contingencies - Connecticut Yankee Atomic Power Company.”

In February 2008, UI and an NRG affiliate formed GenConn Energy LLC (GenConn), a 50-50 joint venture, for the purpose of constructing peaking generation in Connecticut.  UI’s investment in GenConn is being accounted for as an equity investment, the carrying value of which was $62.8 million and an immaterial amount as of December 31, 2010 and 2009, respectively.  Upon GenConn Middletown’s attainment of commercial operation, which is scheduled for June 2011, outstanding amounts loaned by UI to GenConn, which total $61.8 million at December 31, 2010, will be converted to equity.

On September 29, 2010, GenConn Devon reached its completion date, as it is described in connection with the Equity Bridge Loan (EBL), upon which the portion of amounts borrowed for GenConn Devon were due to be repaid.  Accordingly, UI repaid $55.5 million under the EBL.  The loans UI had made for the construction of the GenConn Devon facility of approximately $55.5 million were converted into equity in September 2010.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

Pension and Other Postretirement Benefits

UI accounts for pension plan costs and other postretirement benefits, consisting principally of health and life insurance, in accordance with the provisions of ASC 715 “Compensation - Retirement Benefits”.  See – Note (G), Pension and Other Benefits.

Impairment of Long-Lived Assets and Investments

ASC 360 “Property, Plant, and Equipment” requires the recognition of impairment losses on long-lived assets when the book value of an asset exceeds the sum of the expected future undiscounted cash flows that result from the use of the asset and its eventual disposition.  If impairment arises, then the amount of any impairment is measured based on discounted cash flows or estimated fair value.

ASC 360 also requires that rate-regulated companies recognize an impairment loss when a regulator excludes all or part of a cost from rates, even if the regulator allows the company to earn a return on the remaining costs allowed.  Under this standard, the probability of recovery and the recognition of regulatory assets under the criteria of ASC 980 must be assessed on an ongoing basis.  As described in ASC 980 earlier in this section, determination that certain regulatory assets no longer qualify for accounting as such could have a material impact on the financial condition of  UI.  At December 31, 2010, UI, as a rate-regulated entity, did not have any assets that were impaired under this standard.

ASC 323 "Investments" requires that a loss in the value of an investment that is other than a temporary decline should be recognized. In accordance with ASC 323, UI reviews its investments accounted for by the equity method for impairment by identifying and measuring losses in the value based upon a comparison of fair value to carrying value.  At December 31, 2010, UI did not have any equity investments that were impaired under this standard.

Stock-Based Compensation

UI participates in stock-based compensation plans sponsored by UIL Holdings. Certain members of management have the opportunity to earn a pre-determined number of performance shares, the number of which is predicated upon the achievement of various pre-defined performance measures over a three-year period.  These performance shares were issued under the UIL Holdings 1999 Amended and Restated Stock Plan prior to 2009 and are now issued under the UIL Holdings 2008 Stock and Incentive Compensation Plan (2008 Stock Plan).  Each award of performance shares vests at the end of a three-year cycle with the actual issuance of UIL Holdings’ common stock in respect of such performance shares following the end of each three-year cycle.  A new three-year cycle begins in January of each year.

UIL Holdings records compensation expense for these performance shares ratably over the three-year period, except in the case of retirement-eligible employees, for whom compensation expense is immediately recognized in accordance with ASC 718 “Compensation-Stock Compensation”, based on the value of the expected payout at the end of each year relative to the performance measures achieved.  An additional $0.6 million of compensation expense was recorded in the first quarter of 2010 with respect to retirement-eligible employees based on the application of ASC 718 retirement-eligible provisions.

A target amount of 89,360 performance shares was granted in March 2010; the average of the high and low market price on the date of grant was $28.24 per share.  In March 2010, upon the vesting of performance shares previously granted, 15,414 shares of common stock were issued to members of management and receipt of 19,991 shares was deferred as stock units.  The number of shares issued and deferred reflects the personal income tax elections of the applicable employees.

In March 2010, UIL Holdings granted a total of 2,789 shares of restricted stock to its President and Chief Executive Officer (CEO) under the 2008 Stock Plan and in accordance with his employment agreement; the average of the high and low market price on the date of grant was $28.24 per share.  Compensation expense for this restricted stock is recorded ratably over the five-year vesting period for such restricted stock.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

In May 2010, UIL Holdings granted 2,996 shares of restricted stock to its Vice President – Information Technology and Chief Information Officer.  The average of the high and low market price on the date of grant was $26.70 per share.  Compensation expense for this restricted stock is recorded ratably over the two-year vesting period for such restricted stock.

Compensation expense of $3.1 million and $2.3 million was recognized for the years ended December 31, 2010 and 2009, respectively, related to the aforementioned restricted stock.

Other Income and (Deductions), net

The following table details the components of the other income and (deductions), net:

	2010			2009
	(In Thousands)
Interest income	$	4,014		$	3,231
Allowance for funds used during construction - equity		7,174			650
Allowance for funds used during construction - debt		4,731			1,305
Conservation & Load Management incentive		1,720			765
Energy generation and load curtailment incentives		928			369
ISO load response, net		1,153			1,913
Miscellaneous other income and (deductions) - net		(3,680	)		(2,680	)
Total Other Income and (Deductions), net	$	16,040		$	5,553

New Accounting Standards

In January 2010, the FASB issued updated guidance to ASC 820 “Fair Value Measurements and Disclosures” which requires disclosure of transfers in and out of assets and liabilities that fall within Level 1 and 2 of the fair value hierarchy, as described in “Note K – Fair Value of Financial Instruments”, as well as the gross presentation of activities within the reconciliation of changes in the fair value of Level 3 assets and liabilities.  This guidance is effective in the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 reconciliation information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years.  These requirements impact footnote disclosures only.  Because UI does not currently have any Level 2 assets or liabilities, implementation of the transfer activity disclosure did not have an impact on UI‘s  financial statements.  The implementation of the reconciliation activity disclosure is not expected to have an impact on UI‘s financial statements.

Amended consolidation guidance applicable to variable interest entities (VIEs) became effective as of January 1, 2010, for interim periods within that first annual reporting period, and for interim and annual periods thereafter.  As a result of implementing this guidance, UI determined that it is not currently required to consolidate any VIEs with which it is associated and therefore, this guidance did not have an impact on UI’s  Balance Sheet, Consolidated Statement of Income or Statement of Cash Flows.  As of December 31, 2010, UI had identified Connecticut Yankee Atomic Power Company (Connecticut Yankee) and GenConn as VIEs, which were not subject to consolidation as UI is not the primary beneficiary because it does not have a controlling financial interest, as defined in ASC 810, in either VIE.  For further discussion of GenConn, see Note (C) “Regulatory Proceedings – Generation.”  For further discussion of Connecticut Yankee, see Note (J) “Commitments and Contingencies.”

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

B)  CAPITALIZATION

Common Stock

UI had 100 shares of common stock; no pare value, outstanding as of December 31, 2010 and 2009.

Stock option transactions related to UI for 2010 and 2009, in shares of UIL Holdings’ stock, are as follows:

						Average
	Number			Option Price		Exercise
	of Options			per Share		Price
Balance - December 31, 2008		45,562		$	21.68-$34.52	$	30.86
Granted		-			N/A		N/A
Forfeited		(336	)		N/A		N/A
Exercised		-			N/A		N/A
Balance - December 31, 2009		45,226		$	21.68-$33.96	$	30.83
Granted		-			N/A		N/A
Forfeited		(3,202	)		N/A		N/A
Exercised		(2,805	)	$	21.68	$	21.68
Balance – December 31, 2010		39,219		$	21.68-$33.96	$	31.65
Exercisable at December 31, 2009		45,226		$	21.68-$33.96	$	30.83
Exercisable at December 31, 2010 (1)		39,219		$	21.68-$33.96	$	31.65

(1)  The intrinsic value of exercisable stock options at December 31, 2010 was immaterial.

As of December 31, 2010 and 2009, the weighted-average remaining contractual lives for those options outstanding were 2.0 years and 2.8 years, respectively.

As of December 31, 2010, total stock option compensation costs were zero, performance share costs were $1.8 million, and restricted stock costs related to non-vested awards not yet recognized were $0.3 million.  The weighted-average period over which the stock option compensation costs, performance-share cost, and restricted stock cost will be recognized is zero months, 8 months, and 14 months, respectively.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

Long-Term Debt
	December 31,
	2010		2009
	(In Thousands)
Pollution Control Revenue Refunding Bonds:
5.75%, 1996 Series, due 2026  (1)		7,500		7,500
4.50% 2010 Series, due 2027 (2)		27,500		27,500
7.13%, 1997 Series, due 2027  (3)		71,000		71,000
6.88%, 2009 Series, due 2029  (4)		25,000		25,000
Auction Rate, 2003 Series, due 2033  (5)		64,460		64,460
Notes:
6.06% Senior Notes, Series A and B, due 2017		70,000		70,000
6.26% Senior Notes, Series C and D, due 2022		77,000		77,000
6.51% Senior Notes, Series E and F due 2037		28,000		28,000
6.46% Senior Notes , Series A and 6.51%, Senior Notes, Series B, due 2018		100,000		100,000
6.61% Senior Notes, Series C, due 2020		50,000		50,000
5.61% Senor Notes, due 2025		50,000		50,000
6.09% Senior Notes, due 2040		100,000		-
Equity Bridge Loan		61,783		107,773
Long-Term Debt		732,243		678,233
Less:  Current portion of long-term debt		61,783		53,970
Net Long-Term Debt	$	670,460	$	624,263

(1) The interest rate on these Bonds was fixed at 3.00% on February 1, 2004 for a five-year period ending February 1, 2009.  On February 2, 2009, these Bonds were remarketed, and the interest rate was set at 5.75% for a three-year period ending February 1, 2012.

(2) The interest rate on these Bonds was fixed at 3.65% on February 1, 2005 for a five-year period ending February 1, 2010.  On February 1, 2010, the Bonds were refunded with the proceeds from the issuance of $27.5 million of tax-exempt bonds on January 28, 2010 at an interest rate of 4.5% for a five-year, 5-month period ending July 1, 2015.

(3) The interest rate on these Bonds was fixed at 3.50% on February 2, 2004 for a five-year period ending February 1, 2009.  On February 2, 2009, these Bonds were remarketed, and the interest rate was set at 7.125% for a three-year period ending February 1, 2012.

(4) The interest rate on these Bonds was fixed at 3.25% on February 5, 2003 for a four-year, 10-month period ending December 3, 2007.  On December 3, 2007, the interest rate was reset from 3.25% to 3.90% for a one-year period ending December 1, 2008.  On December 1, 2008, UI purchased the Bonds. On March 18, 2009 $25 million of tax-exempt bonds were refunded with the proceeds from the issuance of $25 million of new tax-exempt bonds, at a fixed interest rate of 6.875%, for a period of approximately three years to February 1, 2012

(5) The interest rate on these Bonds is reset through an auction held every 35 days.  On March 28, 2011, the interest rate on the Bonds was 0.495%.

The fair value of UI‘s long-term debt was $779.9 million and $704.2 million as of December 31, 2010 and 2009, respectively, which was estimated based on market conditions.  The expenses to issue long-term debt are deferred and amortized over the life of the respective debt issue or the fixed interest-rate period in the case of Pollution Control Revenue Refunding Bonds.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

Information regarding maturities and mandatory redemptions/repayments are set forth below:

	2011	2012	2013	2014	2015 & thereafter
(In Thousands)
Maturities	$61,783	$ -	$ -	$ -	$670,460

On May 13, 2010, UI entered into a note purchase agreement with a group of institutional accredited investors providing for the sale of senior unsecured 6.09% notes in the principal amount of $100 million, due on July 27, 2040.  Such notes were issued on July 27, 2010.

On February 1, 2010, $27.5 million of tax-exempt bonds were refunded with the proceeds from the issuance of $27.5 million of new tax-exempt bonds, at a fixed interest rate of 4.5%, for a period of five years and five months.

In April 2009, UI closed on a bank financing in the amount of $121.5 million with a syndicate of banks (the Equity Bridge Loan or EBL), the proceeds of which are being used by UI to fund its commitments as a 50% owner of GenConn.  GenConn has directed $55.5 million of such amount to GenConn Devon LLC (GenConn Devon), and UI expects that GenConn will direct an amount between $63.0 million and $66.0 million borrowed under the EBL to GenConn Middletown LLC (GenConn Middletown), each of which is a wholly owned subsidiary of GenConn, for use in the construction of peaking generation facilities by those entities.  UI draws on this facility as needed to fund its commitments to GenConn as construction progresses.  On September 29, 2010, GenConn Devon reached its completion date, as it is described in connection with the EBL, upon which the portion of amounts borrowed for GenConn Devon were due to be repaid.  Accordingly, UI repaid $55.5 million under the EBL and made its equity investment of approximately $55.5 million in GenConn Devon in September 2010.  Borrowings under this facility as of December 31, 2010 were $61.8 million.  UI made equity investments for its 50% share in October and December of 2010, totaling $6 million, and expects to make an additional equity commitment of up to $9.0 million for the construction of the GenConn Middletown peaking generation facility.

GenConn obtained project financing in April 2009 in a separate transaction that makes $243 million available to GenConn for construction and related activities, and $48 million available under a working capital facility (collectively, the Project Financing).  UI expects that those funds, together with the funds committed by UI and GenConn’s other 50% owner, NRG Energy, will be sufficient to allow GenConn to complete the construction of its planned peaking generation facilities.

On September 28, 2010, UIL Holdings entered into a Sponsor Guaranty and Payment Agreement in favor of the Royal Bank of Scotland PLC, as Administrative Agent under the Project Financing arrangement, whereby UIL Holdings guarantees to pay an amount up to $6 million in respect of amounts related to the former general contractor claims and litigation expenses as they relate to the claims described in Note (J) “Commitments and Contingencies – GenConn.”

The remaining balance under the EBL must be repaid upon the earlier of its maturity date or the attainment of commercial operation for GenConn Middletown.  The maturity date of the loan is April 19, 2011, and may be extended up to July 23, 2011, as long as on the date of extension, project construction is continuing and the Project Financing is not due and payable.

 (C)  REGULATORY PROCEEDINGS

Rates

In rulings throughout 2009, the DPUC issued its final decision regarding UI’s application requesting an increase in distribution rates (the 2009 Decisions), the results of which included a $6.8 million increase in revenue requirements for 2009, compared to 2008.  Because a larger, previously approved increase in revenue requirements for 2009 had gone into effect January 1, 2009, UI returned approximately $1.0 million to ratepayers through a one-time adjustment in April 2009.

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NOTES TO FINANCIAL STATEMENTS - (continued)

The 2009 Decisions provided for an allowed distribution return on equity of 8.75%, a decrease from the previously approved 9.75%, and a capital structure of 50% equity and 50% debt, compared to the previously approved 48% equity and 52% debt.  The 2009 Decisions continued the prior earnings sharing mechanism structure, applying to the new 8.75% allowed return, whereby 50% of any earnings over the allowed twelve month level is returned to customers and 50% is retained by UI.  Given the effective date of the 2009 Decisions, UI’s weighted average allowed distribution return on equity for 2009 was 8.84%.  Additionally, the 2009 Decisions provided for a two year pilot program for full decoupling of distribution revenues from sales, recovery of updated pension and postretirement expense for 2010, a partial reconciliation for the as-issued cost of new debt, and an additional increase in distribution revenue requirements of $19.4 million for 2010.

The 2009 Decisions also provided for the establishment of a regulatory asset to address the portion of the actual increase in pension and postretirement expense for 2009 and 2010 that was not included in rates.  For 2009, a $10.2 million regulatory asset was approved and established, for which full recovery in the 2010 rate year was subsequently approved by the DPUC.  In late 2009, the DPUC also approved the 2010 cash recovery of $11.4 million for UI’s estimated 2010 pension and postretirement expense not previously included in 2010 rates.

On April 1, 2010, UI filed its ratemaking proposal and underlying decoupling analysis for the 2009 rate year ended February 3, 2010.  On September 1, 2010, the DPUC issued its final decision in this matter approving a decoupling charge totaling approximately $1.6 million to be recovered from ratepayers over a twelve month period commencing in October 2010.  In addition to the decoupling charge, the DPUC also approved a pension and earnings sharing over-recovery credit totaling approximately $3.6 million to be refunded to ratepayers over the same twelve month period commencing in October 2010.  The DPUC also approved the continuance of the decoupling pilot program beyond the 2010 rate year and until such time that a final decision is reached regarding whether to continue, modify or terminate the decoupling mechanism.  UI expects such determination to be made in connection with UI’s 2010 rate year decoupling results filing to be submitted to the DPUC by April 4, 2011.

In December 2010, UI received a letter ruling approving rates effective January 1, 2011 incorporating the above mentioned distribution rate changes along with previously approved changes to the Generation Services Charges (GSC), Non-Bypassable Federally Mandated Congestion Charges (NBFMCC), transmission and system benefits charge.  Additionally, last resort service GSC rates have been approved for the period through March 31, 2011.

Other Proceedings

UI generally has several regulatory proceedings open and pending at the DPUC at any given time.  Examples of such proceedings include an annual DPUC review and reconciliation of UI’s Competitive Transition Assessment (CTA) and Systems Benefits Charges (SBC) revenues and expenses, dockets to consider specific restructuring or electricity market issues, consideration of specific rate or customer issues, and review of conservation programs.

UI files semi-annual true-ups with the DPUC regarding Bypassable Federally Mandated Congestion Charges (BFMCC) and NBFMCC.  These customer charges relate to “congestion costs” associated with not having adequate transmission infrastructure to move energy from the generating sources to the consumer and costs associated with ensuring adequate capacity on the electric system, such as peaking generation and capacity CfDs with generators.  These costs change from time to time and the semi-annual true-ups provide a mechanism for the electric distribution companies to adjust the charges to customers that allow the companies to recover the Federally Mandated Congestion Charges (FMCC).

Pension and Postretirement Expenses

In response to the Internal Revenue Service (IRS) mandated change in mortality tables utilized for certain Employee Retirement Income Security Act of 1974 (ERISA)-related liability calculations, effective January 1, 2007, the DPUC allowed regulatory treatment for the change in pension and postretirement expenses resulting from the use of the new

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NOTES TO FINANCIAL STATEMENTS - (continued)

mortality tables.  In the 2009 Decisions, the DPUC approved the recovery of these expenses over a four-year period beginning in 2009.  As of December 31, 2010, the remaining regulatory asset was approximately $2.2 million.

The 2009 Decisions also provide for the establishment of an annual regulatory asset to address a portion of the actual increase in pension and postretirement expense for each of 2009 and 2010.  As of December 31, 2009, UI had recorded a regulatory asset of approximately $10.2 million which was fully recovered in 2010.  Additionally, $11.4 million was included in rates in 2010 for UI’s estimate of 2010 pension and postretirement expense.

Power Supply Arrangements

UI’s retail electricity customers are able to choose their electricity supplier.  Since January 1, 2007, UI has been required to offer standard service to those of its customers who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts.  In addition, UI is required to offer supplier of last resort service to customers who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier licensed in Connecticut.

UI must procure its standard service power pursuant to a procurement plan approved by the DPUC.  The procurement plan must provide for a portfolio of service agreements procured in an overlapping pattern over fixed time periods (a laddering approach).  In June 2006, the DPUC approved a procurement plan for UI.  As required by Connecticut statute, a third party consultant retained by the DPUC works closely with UI in the procurement process and to provide a joint recommendation to the DPUC as to selected bids.

UI has wholesale power supply agreements in place for the supply of all of its standard service customers for all of 2011, 50% for 2012, and 10% for 2013.  Supplier of last resort service is procured on a quarterly basis.  UI determined that its contracts for standard service and supplier of last resort service are derivatives under ASC 815 “Derivatives and Hedging” and elected the “normal purchase, normal sale” exception under ASC 815 “Derivatives and Hedging”.  As such, UI regularly assesses the accounting treatment for its power supply contracts.  These wholesale power supply agreements contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt was to fall below investment grade.  In October 2010, Moody’s Investor Services (Moody’s) released its updated credit opinion for UI and maintained its Baa2 rating with a stable outlook.   In October 2010, Standard & Poors’ Investor Services (S&P) released its updated credit opinion for UI, maintaining its BBB rating with a stable outlook.  If UI’s credit rating were to decline one rating and UI were to be placed on negative credit watch, monthly amounts due and payable to the power suppliers would be accelerated to semi-monthly payments.  UI’s credit rating would have to decline two ratings to fall below investment grade at either rating service.  If this were to occur, UI would have to deliver collateral security in an amount equal to the receivables due to the sellers for the thirty day period immediately preceding the default notice.  If such a situation had been in effect as of December 31, 2010, UI would have had to post approximately $17.5 million in collateral.

As a result of an April 2008 DPUC decision, UI is permitted to seek long-term contracts for up to 20% of standard service requirements, the goal of which is to obtain long-term energy supply contracts and Connecticut Class I Renewable Energy Certificates for UI’s standard service customers that will result in an economic benefit to ratepayers, both in terms of risk and cost mitigation.  UI continues to keep apprised of possible long term contracts that could benefit customers.

Derivatives

As discussed in Note (A) “Statement of Accounting Policies”, the DPUC required that UI and CL&P execute long-term contracts with four new selected capacity resources and subsequently approved four CfDs, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price.  As directed by the DPUC, UI executed two of the contracts and CL&P executed the other two contracts, all of which are subject to the sharing agreement described in Note (A) “Statement of Accounting Policies”.

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NOTES TO FINANCIAL STATEMENTS - (continued)

New Renewable Source Generation

Under Connecticut law, electric distribution companies are required to enter into contracts to purchase in the future the output of new renewable source generation totaling at least 150 MW, at prices and upon terms approved by the DPUC in accordance with statutory requirements.  In 2007, one contract was approved by the DPUC.  UI was not a party to that contract but, as directed by the DPUC, UI has executed a sharing agreement with CL&P whereby UI pays approximately 20% of the costs and obtains approximately 20% of the benefits of the contract.  This contract will be accounted for on an accrual basis.  In January 2008, the DPUC issued a decision approving seven projects; UI is a party to contracts relating to two of these projects.  UI signed a contract to purchase, over a fifteen year time period, 100% of the delivered products generated by the Stamford Hospital Fuel Cell Combined Heat and Power Project which has a 4.8 MW capacity.  This contract will be accounted for as an operating lease.  UI also signed a contract to purchase, over a fifteen year time period, 84.5% of the delivered products generated by the South Norwalk Bio-Fuel Project which has a 30 MW capacity and which will be accounted for on an accrual basis.  In April 2009, the DPUC approved five additional fuel cell projects to which accrual accounting will be appliedand for which contracts were executed by CL&P in July 2009.  All of these contracts will be subject to the cost sharing agreement with CL&P.  UI’s costs associated with all such contracts are recoverable, whether UI is a direct party or pursuant to the sharing agreement.

Federal Energy Regulatory Commission (FERC)

UI recovers its transmission revenue requirements on a prospective basis, subject to reconciliation with actual revenue requirements.  UI is required to file information regarding its approved formula rates on an annual basis with the FERC.

ISO-NE and RTO-NE

ISO-NE, an independent, not-for-profit corporation, was approved by the FERC as the regional transmission organization for New England (RTO-NE) on February 1, 2005.  ISO-NE is responsible for the reliable operation of the region’s bulk electric power system and fair administration of the region’s wholesale electricity marketplace.  ISO-NE also is responsible for the management of the comprehensive bulk electric power system and wholesale markets’ planning processes that address the region's electricity needs.

In March 2008, the FERC issued an order on rehearing (Rehearing Order) establishing allowable ROEs for transmission projects of transmission owners in New England, including UI.  In the Rehearing Order, the FERC established the base-level ROE of 11.14% beginning in November 2006.  The Rehearing Order also confirmed a 50 basis point ROE adder on Pool Transmission Facilities (PTF) for participation in the RTO-NE and a 100 basis point ROE incentive for projects included in the ISO-NE Regional System Plan  that were completed and on line as of December 31, 2008.  The Middletown/Norwalk Transmission Project received this 100 basis point ROE adder.    For projects placed in service after December 31, 2008, incentives may be requested from the FERC, through a specific showing justifying the incentive, on a project-specific basis.

In May 2008, several public entities, including the DPUC (petitioners), filed a petition with the United States Court of Appeals for the District of Columbia Circuit (U.S. Court of Appeals) challenging the Rehearing Order.  In January 2010, the U.S. Court of Appeals issued a decision upholding the FERC order, and in April 2010, it denied the petitioners request for a rehearing by the full court.

UI’s overall transmission ROE is determined by the mix of UI’s transmission rate base between new and existing transmission assets, and whether such assets are PTF or non-PTF.  UI’s transmission assets are primarily PTF.  For 2010, UI’s overall allowed weighted-average ROE for its transmission business was 12.5%.

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NOTES TO FINANCIAL STATEMENTS - (continued)

New England East-West Solution

On July 14, 2010, UI entered into an agreement (Agreement) with CL&P, under which UIhas the right to invest in, and own transmission assets associated with, the Connecticut portion of CL&P’s New England East West Solution (NEEWS) projects to improve regional energy reliability.  The Agreement is subject to state and federal regulatory approval.  On July 15, 2010, UI and CL&P filed a joint application with the DPUC requesting such approval and on October 13, 2010, the DPUC approved the request.  On December 3, 2010, UI and CL&P filed a joint application with the FERC also requesting approval for the future transfer of assets from CL&P to UI and on February 7, 2011, the FERC approved the request with minimal conditions.

NEEWS consists of four inter-related transmission projects being developed by subsidiaries of Northeast Utilities (NU), the parent company of CL&P, in collaboration with National Grid USA.  Three of the projects have portions sited in Connecticut:  (1) the Greater Springfield Reliability Project, (2) the Interstate Reliability Project and (3) the Central Connecticut Reliability Project.  NU currently projects that the cost of the Connecticut portion of these projects will be approximately $828 million.

Under the terms of the Agreement, UI has the option to make quarterly deposits to CL&P in exchange for ownership of specific transmission assets as they are placed in service.  Subject to final regulatory approval, UI will have the right to invest up to the greater of $60 million or an amount equal to 8.4% of CL&P’s costs for the Connecticut portions of the NEEWS projects.  Based upon NU's currently projected costs, UI expects this amount to approximate $69 million.  As assets are placed in service, CL&P will transfer title to certain transmission assets to UI in proportion to its investments, but CL&P will continue to maintain these portions of the transmission system pursuant to an operating and maintenance agreement with UI.  Also, under the terms of the Agreement, there are certain circumstances under which CL&P can terminate the Agreement, but such termination would not affect assets previously transferred to UI.

In December 2010, UI made deposits totaling $7.2 million in NEEWS and expects to make the remaining investments over a period of three to five years, depending on the timing and amount of CL&P’s capital expenditures and the projects’ in service dates.

Transmission Adjustment Clause

UI makes a semi-annual transmission adjustment clause (TAC) filing with the DPUC setting forth its actual transmission revenues, projected transmission revenue requirement, and the required TAC charge or credit so that any under- or over-collections of transmission revenues from prior periods are reconciled along with the expected revenue requirements for the next six months from filing.  The DPUC holds an administrative proceeding to approve the TAC charge or credit and holds a hearing to determine the accuracy of customer billings under the TAC.  The TAC tariff and this semi-annual change of the TAC charge or credit facilitates the timely matching of transmission revenues and transmission revenue requirements.

Equity Investment in Peaking Generation

UI is a 50-50 joint venturer with NRG Energy, Inc. (NRG) in GCE Holding LLC, whose wholly owned subsidiary, GenConn Energy LLC (collectively, GenConn), was chosen by the DPUC to build and operate new peaking generation plants to help address Connecticut’s need for power generation during the heaviest load periods.

The two peaking generation projects, each with a nominal capacity of 200 megawatts (MW), are located at NRG’s existing Connecticut plant locations in Devon and Middletown.  GenConn’s Devon plant is now operating, and its Middletown plant is scheduled to be in operation by June 2011.  GenConn recovers its costs under a contract for differences (CfD) agreement which is cost of service based.  GenConn has signed CfDs for both projects with The Connecticut Light & Power Company (CL&P).  The cost of the contracts will be paid by customers and will be subject to a cost-sharing agreement whereby approximately 20% of the cost is borne by UI customers and approximately 80% by CL&P customers.

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NOTES TO FINANCIAL STATEMENTS - (continued)

GenConn filed a rate case request with the DPUC in December 2009, seeking approval of 2010 revenue requirements for the period commencing June 1, 2010 for the GenConn Devon facility.  The DPUC issued a final decision on May 26, 2010, approving the proposed $18.7 million 2010 revenue requirement for the GenConn Devon plant.  GenConn bid the full capacity of the GenConn Devon facility into the ISO New England, Inc. (ISO-NE) locational forward reserve market (LFRM) for the summer 2010 period (June 1, 2010 to September 30, 2010) and for the winter period (October 1, 2010 to May 31, 2011).  The DPUC’s decision states that final determination regarding prudent construction costs will be made in the 2013 revenue requirements proceeding to be filed in 2012, by which time the GenConn Devon and GenConn Middletown facilities are expected to be operational and construction costs are complete for both facilities.  GenConn expects to recover such costs in DPUC-approved future revenues.

The four units at the GenConn Devon facility were released to the ISO-NE LFRM (three in June 2010 and one in July 2010), but GenConn incurred availability penalties for such units not being available to the ISO-NE LFRM as of June 1, 2010.  GenConn was able to mitigate these penalties by obtaining coverage for a portion of the unavailable capacity.  UI’s 50% share in the gain from equity investments of $1.2 million, included in UI’s Financial Statements as of December 31, 2010, includes these mitigated penalties and certain other damages, as well as ISO-NE revenues for units that were released to the ISO-NE LFRM, revenues associated with its CfD with CL&P, and normal operating expenses.  On September 10, 2010, the GenConn Devon facility met its remaining CfD commercial operation requirements as defined by the CfD.

GenConn filed a rate case request with the DPUC on July 30, 2010, seeking approval of 2011 revenue requirements for the period commencing January 1, 2011 for the GenConn Devon facility and June 1, 2011 for the GenConn Middletown facility.  The DPUC issued a final decision on December 29, 2010, approving 2011 revenue requirements for the GenConn Devon facility of $36.8 million and $22.6 million for the GenConn Middletown facility.  As a result of changed financial market conditions and updated cost information, GenConn project costs have increased over the proposal it originally submitted to the DPUC in 2008.  The increase was driven primarily by increased financing costs and the cost to build interconnection facilities at the Middletown site.  The DPUC has ruled that prudently incurred financing costs, interconnection costs and taxes will be recoverable and, therefore,GenConn expects to recover such costs in DPUC-approved future revenues.  The CfDs provide for a true-up of revenue from the ISO New England Markets in which GenConn participates to DPUC approved revenue requirements.

(D)  SHORT-TERM CREDIT ARRANGEMENTS

On November 17, 2010, UIL Holdings and its regulated subsidiaries including UI entered into a revolving credit agreement with a group of banks named therein that will expire on November 17, 2014 (the credit facility).  The borrowing limit under the credit facility is $400 million, of which $250 million is available to UI.  The credit facility permits borrowings at fluctuating interest rates and also permits borrowings for fixed periods of time specified by each Borrower at fixed interest rates determined by the Eurodollar interbank market in London (LIBOR).  The credit facility also permits the issuance of letters of credit of up to $50 million.  Simultaneously with the closing of the new facility, UIL Holdings and UI terminated their existing credit agreement, which was due to mature on December 22, 2011.

As of December 31, 2010, UI had no short-term borrowings under the Credit Facility.  Available credit under this facility at December 31, 2010 was $392 million for UIL Holdings and its subsidiaries in the aggregate.  UIL Holdings records borrowings under this facility as short-term debt, but the agreement has longer term commitments from banks allowing the Company to borrow and reborrow funds, at its option, to November 17, 2014, thus affording it flexibility in managing its working capital requirements.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

Information with respect to UI’s short-term borrowings is set forth below:

	2010			2009
	($ In Thousands)
Maximum aggregate principal amount of short-term borrowing outstanding at any month-end	$	25,000		$	174,000
Average aggregate short-term borrowings outstanding during the year*	$	10,778		$	65,526
Weighted average interest rate*		0.67	%		0.88	%
Principal amounts outstanding at year-end	$	-		$	-
Annualized interest rate on principal amounts outstanding at year-end		N/A			0.00	%
Fees*	$	273		$	513

*Average short-term borrowings represent the sum of daily borrowings outstanding, weighted for the number of days outstanding and divided by the number of days in the period.  The weighted average interest rate is determined by dividing interest expense by the amount of average borrowings.  Fees are excluded from the calculation of the weighted average interest rate.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

(E) INCOME TAXES
	2010			2009
	(In Thousands)
Income tax expense consists of:
Income tax provisions:
Current
Federal	$	(16,907	)	$	37,550
State		(547	)		4,457
Total current		(17,454	)		42,007
Deferred
Federal		55,386			(2,316	)
State		1,922			(4,812	)
Total deferred		57,308			(7,128	)
Investment tax credits		(146	)		(146	)
Total income tax expense	$	39,708		$	34,733
Income tax components charged as follows:
Operating tax expense	$	41,536		$	37,333
Nonoperating tax benefit		(2,331	)		(2,504	)
Equity investment tax expense (benefit)		503			(96	)
Total income tax expense	$	39,708		$	34,733
The following table details the components
of the deferred income tax provision:
Property related (accelerated depreciation and other)	$	72,721		$	10,289
Investment in GenConn		19,201			132
Bond redemption costs		(340	)		(340	)
Incentive compenstation plans		268			(634	)
Seabrook lease buyout		(2,542	)		(1,367	)
Post retirement benefits		(2,271	)		(2,870	)
Pension benefits		(11,182	)		(5,941	)
Regulatory deferrals		(19,213	)		(5,278	)
Other - net		666			(1,119	)
Deferred income tax provision - net	$	57,308		$	(7,128	)

 

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

Total income taxes differ from the amounts computed by applying the federal statutory tax rate to income before taxes.  The reasons for the differences are as follows:

	2010			2009
	(In Thousands)
Computed tax at federal statutory rate	$	36,211		$	32,097
Increases (reductions) resulting from:
ITC taken into income		(147	)		(147	)
Allowance for equity funds used during construction		(2,511	)		(227	)
Amortization of nuclear plant regulatory assets		7,661			3,696
Book depreciation in excess of non-normalized tax depreciation		(708	)		313
State income taxes, net of federal income tax benefits		894			(230	)
ESOP dividend payments		(488	)		(457	)
Mark-to-market adjustments to non-qualified pension investments		(208	)		(391	)
Other items, net		(996	)		79
Total income tax expense	$	39,708		$	34,733
Book income before income taxes	$	103,460		$	91,706
Effective income tax rates		38.4	%		37.9	%

In 2010 and 2009, the combined statutory federal and state income tax rate for UI was 40.4%. Legislation enacted in Connecticut in 2009 imposed a 10% surcharge on the corporation business tax for the years 2009, 2010, and 2011.  This surcharge increased the statutory rate of Connecticut corporation business tax for 2009 and 2010 from 7.5% to 8.3% and increased the combined statutory federal and state income tax rate for UI for 2009 and 2010 to 40.4%.

Differences in the treatment of certain transactions for book and tax purposes occur which cause the rate of UI reported income tax expense to differ from the statutory tax rate described above.  The effective book income tax rate for the year ended December 31, 2010 as 38.4%, as compared to 37.9% for the year ended December 31, 2009.  The increase in the 2010 effective book income tax rates was due primarily to the non-normalized effect associated with increased nuclear stranded cost amortization in the CTA in 2010.

Federal income tax legislation enacted during the fourth quarter of 2010 provides for accelerated capital recovery for federal income tax purposes.  As a result, during the fourth quarter of 2010, UI recognized additional tax deductions for capital recovery that resulted in a cash benefit of approximately $27.5 million.  A portion of this cash benefit was recognized through lower cash requirements for federal income tax deposits required in the fourth quarter of 2010.  The remainder of the cash benefit will be recognized through lower operational financing requirements during 2011.

During 2010, UI recognized a significant one-time income tax deduction, which it reflected on its 2009 state and federal income tax returns, related to repair and maintenance costs it had previously capitalized for tax purposes.  This one-time income tax deduction resulted in a cash benefit of approximately $40.5 million.  The decreases in current income tax expense and increase in deferred income tax expense for the year ended December 31, 2010, compared to the year ended December 31, 2009, were primarily due to this one-time income tax deduction which was deferred for book purposes.  As a result, as of December 31, 2010, UI had gross unrecognized tax benefits of approximately $11.4 million, including approximately $0.1 million of interest, of which none would impact the effective tax rate if recognized.  UI expects the amount of unrecognized tax benefits to increase by $2 million to $3 million in the next 12 months.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

The following table sets forth a reconciliation of the changes in the gross income tax reserves for the years ended December 31, 2010 and 2009:

	2010		2009
	(In Thousands)
Balance as of December 31,	$	-	$	-
Increases for tax positions related to prior years		8,922		-
Increases for tax positions related to current year		2,427		-
Balance as of December 31,	$	11,349	$	-

UI is subject to the United States federal income tax statutes administered by the Internal Revenue Service (IRS) and the income tax statues of the State of Connecticut.  UI’s results are included in the consolidated tax return of its parent, UIL Holdings, for both State of Connecticut and federal income tax purposes and UI determines a separate tax provision for this purpose.  As of December 31, 2010, the tax years 2007, 2008, and 2009 remain open and subject to audit for State of Connecticut income tax purposes.  As of December 31, 2010, the tax years 2008 and 2009 are open and subject to audit for federal income tax purposes.  During 2009, the IRS closed examinations of the tax years 2004, 2005, 2006, and 2007.  The IRS examination of the tax years 2004, 2005, and 2006 resulted in an immaterial assessment to UI.  The examination of the tax year 2007 resulted in no additional assessment or refund to UI.

At December 31, 2010, UI had non-current deferred tax liabilities for taxable temporary differences of $434.9 million and non-current deferred tax assets for deductible temporary differences of $100.6 million, resulting in a net non-current deferred tax liability of $334.3 million.  UI had current deferred tax assets of $19.6 million at December 31, 2010.  UI did not have any current deferred tax liabilities at December 31, 2010.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

The following table summarizes UI’s deferred tax assets and liabilities as of December 31, 2010 and 2009:

	2010			2009
	(In Thousands)
Deferred income tax assets:
Regulatory asset related to pension and other post-retirement benefits	$	69,358		$	66,158
Post-retirement benefits		12,106			9,835
Regulatory deferrals		10,966			(3,568	)
ASC 740 gross-up effect on deferred taxes		6,477			6,559
Connecticut Yankee equity investment		3,145			3,146
Long-term incentive plan		2,992			2,197
Vacation accrual		2,728			2,573
Supplemental pensions		2,134			2,068
Uncollectibles		1,439			1,865
Post-employment benefits		700			462
Gains on sale of property		662			662
Interest during construction		442			484
Other		7,050			6,375
	$	120,199		$	98,816
Deferred income tax liabilities:
Plant basis differences	$	167,391		$	134,192
Accelerated depreciation timing differences		154,067			131,610
Regulatory asset related to pension and other post-retirement benefits		69,358			66,158
Investment in GenConn Energy		19,332			132
Pension		(2,047	)		7,851
Seabrook lease buyout		16,641			19,184
Bond redemption costs		5,786			6,126
Other		4,375			7,939
	$	434,903		$	373,192

ASC 740 requires that all current deferred tax assets and liabilities within each particular tax jurisdiction be offset and presented as a single amount in the Balance Sheet.  A similar procedure is followed for all non-current deferred tax assets and liabilities.  Amounts in different tax jurisdictions cannot be offset against each other.  The amount of deferred income taxes as of December 31, 2010 and 2009 included on the following lines of the Balance Sheet is as follows:

	2010		2009
	(In Thousands)
Assets:
Deferred and refundable income taxes	$	19,555	$	4,391
Liabilities:
Deferred income taxes		334,259		278,767
Deferred income taxes – net	$	314,704	$	274,376

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

(G)  PENSION AND OTHER BENEFITS

Pension Plan

The United Illuminating Company Pension Plan (the UI Pension Plan) covers the majority of employees of UIL Holdings and UI.  UI also has a non-qualified supplemental pension plan for certain employees and a non-qualified retiree-only pension plan for certain early retirement benefits.  The net pension expense for these plans for 2010 and 2009 were $21.2 million and $16.7 million, respectively.

Disclosures pertaining to the UI Pension Plan are in accordance with ASC 715 Compensation-Retirement Benefits.  UI has an investment policy addressing the oversight and management of pension assets and procedures for monitoring and control.  UI has engaged Russell Investments as the trustee and investment manager to assist in areas of asset allocation and rebalancing, portfolio strategy implementation, and performance monitoring and evaluation.

The goals of the asset investment strategy are to:

·   Achieve long-term capital growth while maintaining sufficient liquidity to provide for current benefit payments and UI Pension Plan operating expenses.

·   Provide a total return that, over the long term, provides sufficient assets to fund UI Pension Plan liabilities subject to an appropriate level of risk, contributions and pension expense.

·   Optimize the return on assets, over the long term, by investing primarily in a diversified portfolio of equities and additional asset classes with differing rates of return, volatility and correlation.

·   Diversify investments within asset classes to maximize preservation of principal and minimize over-exposure to any one investment, thereby minimizing the impact of losses in single investments.

The UI Pension Plan seeks to maintain compliance with the Employee Retirement Income Security Act of 1974 (ERISA) as amended, and any applicable regulations and laws.

The Retirement Benefits Plans Investment Committee of the Board of Directors oversees the investment of UI Pension Plan assets in conjunction with management and has conducted a review of the investment strategies and policies of the UI Pension Plan.  This review included an analysis of the strategic asset allocation, including the relationship of UI Pension Plan assets to UI Pension Plan liabilities, and portfolio structure.  The Retirement Benefits Plans Investment Committee has left the target asset allocation for 2011 unchanged from 2010 for both the pension and other postretirement employee benefit funds.  In the event that the relationship of UI Pension Plan assets to UI Pension Plan liabilities changes, the Retirement Benefits Plans Investment Committee will consider changes to the investment allocations.  The other postretirement employee benefit fund assets are invested in a balanced mutual fund and, accordingly, the asset allocation mix of the balanced mutual fund may differ from the target asset allocation mix from time to time.  The 2011 target asset allocation, which may be revised by the Retirement Benefits Plans Investment Committee, is as follows:  65% Equity securities, 25% Debt securities and 10% other.

Funding policy for the UI Pension Plan is to make annual contributions that satisfy the minimum funding requirements of ERISA but that do not exceed the maximum deductible limits of the Internal Revenue Code. These amounts are determined each year as a result of an actuarial valuation of the UI Pension Plan.  Asset values as of December 31, 2010 and December 31, 2009 were approximately $245.1 million and $231.3 million, respectively.  UIL Holdings contributed $7.5 million to the UI Pension Plan in 2010 and has a minimum funding requirement for 2011 currently estimated at $21 million.  Depending upon final actuarial calculations, the 2011 contribution may ultimately range between $45 million and $50 million.

UI has established a supplemental retirement benefit trust and through this trust purchased life insurance policies on certain officers of UI to fund the future liability under the non-qualified supplemental plan.  The cash surrender value of these policies is included in “Other investments” on the Balance Sheet.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

There is potential variability to the pension expense calculation.  Changes in certain of the underlying assumptions could have a material impact on pension expenses.  For example, if there had been a 0.25% change in the discount rate assumed for the qualified pension plan and non-qualified plan, respectively, the 2010 pension expense would have increased or decreased inversely by $1.4 million for the qualified plan and an immaterial amount for the non-qualified plan.  If there had been a 1% change in the expected return on assets, the 2010 pension expense would have increased or decreased inversely by $2.7 million for the qualified pension plan and would not have changed for the non-qualified plan.

Other Postretirement Benefits

In addition to providing pension benefits, UI also provides Other Postretirement Benefits (OPEB), consisting principally of health care and life insurance benefits, for retired employees and their dependents.  UI does not provide prescription drug benefits for Medicare-eligible employees in its postretirement health care plans.  Non-union employees who are 55 years of age and whose sum of age and years of service at time of retirement is equal to or greater than 65 are eligible for benefits partially subsidized by UI.  The amount of benefits subsidized by UI is determined by age and years of service at retirement.  For funding purposes, UI established a 401(h) account in connection with the Pension Plan and Serial Voluntary Employee Benefit Association Trust (VEBA) accounts for the years 2007 through 2020 to fund OPEB for UI’s non-union employees who retire on or after January 1, 1994.  These VEBA accounts were approved by the IRS and UI contributed $4.5 million to fund the Serial VEBA accounts in 2007.  UI does not expect to make a contribution in 2011 to fund OPEB for non-union employees.

Union employees whose sum of age and years of service at the time of retirement is equal to or greater than 85 (or who are 62 with at least 20 years of service) are eligible for benefits partially subsidized by UI.  The amount of benefits subsidized by UI is determined by age and years of service at retirement.  For funding purposes, UI established a VEBA to fund OPEB for UI’s union employees.  The funding strategy for the VEBA is to select funds that most clearly mirror the pension allocation strategy.  Approximately 38% of UI’s employees are represented by Local 470-1, Utility Workers Union of America, AFL-CIO, for collective bargaining purposes.  Plan assets for the union VEBA consist primarily of equity and fixed-income securities.  UI does not expect to make a contribution in 2011 to fund OPEB for union employees.

There is potential variability to the OPEB plan expense calculation.  Changes in certain of the underlying assumptions could have a material impact on OPEB expenses.  If there had been a 0.25% change in the discount rate assumed, the 2010 OPEB plan expenses would have increased or decreased inversely by $0.3 million; if there had been a 1% change in the expected return on assets, the 2010 OPEB plan expenses would have increased or decreased inversely by $0.2 million.

Assumptions

To develop the expected long-term rate of return on assets assumption, UI considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets assumption for the portfolio.  This resulted in the selection of the 8.5% return on plan assets for 2010.

The projected, long-term average wage increase is 3.8% in 2010 based upon salary data.  For 2010 and 2009, UI utilized the Citigroup Discount Curve to determine discount rates of 5.35% and 5.85%, respectively, for the UI Pension Plan, 5.10% and 5.65%, respectively, for the non-qualified plan, and 5.30% and 5.80%, respectively, for the OPEB plan.  The Citigroup Discount Curve is a spot rate curve developed based upon a bond portfolio.  The discount rate is determined

by combining this curve and the expected payout of UI Pension Plan liabilities.  Management further considers rates of high-quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the Company’s plans.  The health care cost trend rate assumption for all retirees is set at 9.50% in 2010 with such rate decreasing gradually to 5.0% in 2018.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

In accordance with ASC 715, UI utilizes an alternative method to amortize prior service costs and unrecognized gains and losses.  UI amortizes prior service costs for both the Pension Plan and OPEB plan on a straight-line basis over the average remaining service period of participants expected to receive benefits.  UI utilizes an alternative method to amortize unrecognized actuarial gains and losses related to the Pension and OPEB plan over the lesser of the average remaining service period or 10 years.  For ASC 715 purposes, UI does not recognize gain or loss until there is a variance in an amount equal to at least 5% of the greater of the projected benefit obligation or the market-related value of assets.  There is no such allowance for a variance in capturing the amortization of OPEB unrecognized gains and losses.

Defined Contribution Retirement Plan

Since 2005, new employees do not participate in the Pension Plan or receive retiree medical plan benefits.  These employees participate in a different retirement plan, which is a “defined contribution plan,” consisting of the current provisions of UI’s 401(k)/Employee Stock Ownership Plan (KSOP) plus the following benefits:

·   An additional cash contribution of 4.0% of total annual compensation (as defined in the KSOP Plan) to a separate account in the KSOP of new hires.

·   An additional cash contribution of $1,000 per year (pro rata per pay period) into a separate Retiree Medical Fund within the KSOP account for new hires.

·   New employees do not need to contribute to the KSOP to receive these additional cash contribution amounts; they only need to be enrolled in the KSOP Plan.

·   Both additional cash contributions to the KSOP vest 100% after five years of service.

The following table represents the change in benefit obligation, change in plan assets and the respective funded status of UI’s pension and postretirement plans as of December 31, 2010 and 2009.  Plan assets and obligations have been measured as of December 31, 2010 and 2009.

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

							Other Post-Retirement
	Pension Benefits						Benefits
	2010			2009			2010			2009
Change in Benefit Obligation:	(In Thousands)
Benefit obligation at beginning of year	$	371,802		$	348,058		$	69,415		$	69,505
Service cost		7,123			6,133			1,360			1,334
Interest cost		21,088			20,928			3,929			4,137
Participant contributions		-			-			1,101			1,033
Actuarial (gain) loss		30,325			18,261			2,757			(2,085	)
Benefits paid (including expenses)		(22,152	)		(21,578	)		(4,204	)		(4,509	)
Benefit obligation at end of year	$	408,186		$	371,802		$	74,358		$	69,415
Change in Plan Assets:
Fair value of plan assets at beginning of year	$	231,308		$	211,675		$	22,194		$	20,861
Actual return on plan assets		27,967			40,964			2,337			4,224
Employer contributions		7,967			247			859			585
Participant contributions		-			-			1,101			1,033
Benefits paid (including expenses)		(22,152	)		(21,578	)		(4,204	)		(4,509	)
Fair value of plan assets at end of year	$	245,090		$	231,308		$	22,287		$	22,194
Funded Status at December 31:
Projected benefits (less than) greater than plan assets	$	163,096		$	140,494		$	52,071		$	47,221
Amounts Recognized in the Consolidated Balance Sheet consist of:
Current liabilities	$	254		$	511		$	216		$	199
Non-current liabilities	$	162,842		$	139,983		$	51,855		$	47,022
Amounts Recognized as a Regulatory Asset consist of:
Transition obligation (asset)	$	-		$	-		$	1,411		$	2,470
Prior service cost		2,132			2,778			(125	)	$	(228	)
Net (gain) loss		150,633			141,518			19,724			19,501
Total recognized as a regulatory asset	$	152,765		$	144,296		$	21,010		$	21,743
Information on Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Projected benefit obligation	$	408,186		$	371,802			N/A			N/A
Accumulated benefit obligation	$	363,186		$	324,345			N/A			N/A
Fair value of plan assets	$	245,090		$	231,308			N/A			N/A
The following weighted average actuarial assumptions were used in calculating the benefit obligations at December 31:
Discount rate (Qualified Plans)		5.35	%		5.85	%		N/A			N/A
Discount rate (Non-Qualified Plans)		5.10	%		5.65	%		N/A			N/A
Discount rate (Other Post-Retirement Benefits)		N/A			N/A			5.30	%		5.80	%
Average wage increase		3.80	%		3.80	%		N/A			N/A
Health care trend rate (current year)		N/A			N/A			9.50	%		9.50	%
Health care trend rate (2019-2028 forward)		N/A			N/A			5.00	%		5.00	%

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THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS - (continued)

The components of net periodic benefit cost are:

	For the Year Ended December 31,
	Pension Benefits						Other Post-Retirement Benefits
	2010			2009			2010			2009
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	7,123		$	6,133		$	1,360		$	1,334
Interest cost		21,088			20,928			3,929			4,138
Expected return on plan assets		(19,067	)		(17,113	)		(1,754	)		(1,640	)
Amortization of:
Prior service costs		646			697			(103	)		(101	)
Transition obligation (asset)		-			-			1,058			1,058
Actuarial (gain) loss		12,309			14,425			1,950			2,686
Net periodic benefit cost (1)	$	22,099		$	25,070		$	6,440		$	7,475
Other Changes in Plan Assets and Benefit Obligations Recognized as a Regulatory Asset:
Net (gain) loss	$	21,425		$	(5,590	)	$	2,173		$	(4,670	)
Amortization of:
Prior service costs		-			(697	)		(1,058	)		101
Transition obligation (asset)		(646	)					103			(1,058	)
Actuarial (gain) loss		(12,309	)		(14,425	)		(1,950	)		(2,686	)
Total recognized as regulatory asset	$	8,470		$	(20,712	)	$	(732	)	$	(8,313	)
Total recognized in net periodic benefit costs
and regulatory asset	$	30,569		$	4,358		$	5,708		$	(838	)
Estimated Amortizations from Regulatory Assets into Net Periodic Benefit Cost for the period January 1, 2011 - December 31, 2011:
Amortization of transition obligation	$	-		$	-		$	1,020		$	1,059
Amortization of prior service cost		643			645			(101	)		(103	)
Amortization of net (gain) loss		14,032			12,309			2,008			1,950
Total estimated amortizations	$	14,675		$	12,954		$	2,927		$	2,906
The following actuarial weighted average assumptions were used in calculating net periodic benefit cost:
Discount rate		5.10-5.35	%		6.20	%*		5.30	%		6.10	%
Average wage increase		3.80	%		3.80	%		N/A			N/A
Return on plan assets		8.25	%		8.50	%		8.25	%		8.50	%
Health care trend rate (current year)		N/A			N/A			8.50	%		10.00	%
Health care trend rate (2019 forward)		N/A			N/A			5.00	%		5.00	%

 33 -

- 33 -

A one percentage point change in the assumed health care cost trend rate would have the following effects:

	1% Increase		1% Decrease
	(In Thousands)
Aggregate service and interest cost components	$	822	$	(670	)
Accumulated post-retirement benefit obligation	$	10,138	$	(8,370	)

Estimated Future Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

			Other Post-Retirement
Year	Pension Benefits		Benefits
	(In Thousands)
2011	$	24,297	$	3,583
2012	$	28,682	$	3,681
2013	$	24,566	$	3,887
2014	$	25,372	$	4,047
2015	$	27,054	$	4,256
2016-2020	$	140,993	$	24,278

401(k)

UI has a 401(k)/Employee Stock Ownership Plan (KSOP) in which substantially all of its employees are eligible to participate.  The KSOP enables employees to defer receipt of a portion of their compensation, up to statutory limits, and to invest such funds in a number of investment alternatives.  Matching contributions are made to the KSOP, in the form of UIL Holdings’ common stock, based on each employee’s salary deferrals in the KSOP.  For union employees, the matching contribution to the KSOP is 100% of the first 3% of employee compensation deferred and 50% of the next 2% deferred.  The maximum match is 4% of annual salary.  For non-union employees, the matching contribution to the KSOP is 100% of the first 2% of employee compensation deferred.  Matching contributions to the KSOP during 2010 and 2009 were $2.4 million and $2.5 million, respectively

(H)  RELATED PARTY TRANSACTIONS

UI is a 50-50 joint venturer with NRG in GCE Holding LLC, whose wholly owned subsidiary, GenConn, was chosen by the DPUC to build and operate new peaking generation plants to help address Connecticut’s need for power generation during the heaviest load periods.  GenConn had signed a promissory note (the Loan) with UI under which UI advanced up to an aggregate principal amount of $48.5 million to fund GenConn’s construction and other cash needs until permanent financing was arranged.  In connection with the EBL obtained by UI and the Project Financing obtained by GenConn on April 27, 2009, all outstanding balances on the Loan were replaced by a new promissory note, the balance of which was $62.0 million as of December 31, 2010.  See Note (B) “Capitalization – Long-Term Debt” for further discussion regarding the EBL.  Additionally, $3.3 million and $2.0 million of interest income related to the promissory note are included in “Other income and (deductions), net" in the accompanying Statement of Income, for the years ended December 31, 2010 and 2009 respectively,  which is offset by the interest expense incurred by UI under the EBL.

UI and NRG are each making equity investments in GenConn on a 50/50 basis to meet GenConn’s remaining capital requirements not met by the Project Financing.  In September 2010, UI made its equity investment in GenConn Devon in the amount of approximately $55.5 million.  In addition to the funds to be directed to GenConn that are borrowed under the EBL, UI made additional equity investments in October and December of 2010, totaling $6 million, for the construction of the GenConn Middletown peaking generation facility.

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A Director of UIL Holdings holds a beneficial interest in the building located at 157 Church Street, New Haven, Connecticut, where UI leases office space.UI’s lease payments for this office space for the years ended December 31, 2010 and 2009 totaled $10.8 million and $11.0 million, respectively.

A Director of UIL Holdings holds a position on the Board of Directors of People’s United Bank.  UI has a banking relationship with People’s United Bank in connection with the Credit Facility described in Note (D) “Short-Term Credit Arrangements”.  Such Director was not directly involved in any transaction between UI and People’s United Bank.

In 1990, UI formed the United Illuminating Company Foundation (the Foundation) to ensure that UI’s charitable giving would remain constant regardless of the state of economy.  The Foundation focuses its grant making in the service territories of UI.  UIL Holdings made contributions to the Foundation of approximately $1.3 million and $0.5 million in 2010 and 2009, respectively.

Inter-company Transactions

UI receives certain services from, and enters into certain inter-company transactions with, UIL Holdings.  Such transactions relate to payroll, management and executive incentive payouts, outside professional services, and stock options.  Costs of the services that are allocated amongst UI and UIL Holdings are based on actual direct costs incurred by the respective company, which are settled at the end of each month by way of inter-company billings and wire transfers.  At December 31, 2010 and 2009, the Balance Sheet reflects inter-company receivables of $0.3 million and $0.2 million, respectively, and inter-company payables of $3.0 million and $2.9 million, respectively.

Dividends/Capital Contributions

In 2010 and 2009, UI made wire transfers to UIL Holdings on a quarterly basis, representing an amount approximately equal to UI’s forecasted net income, in order to maintain its capitalization structure as allowed per the 2008 Rate Case.  For the years ended December 31, 2010 and 2009, UI accrued dividends to UIL Holdings of $62.1 million and $46.9 million, respectively.

(I)  LEASE OBLIGATIONS

UI has lease arrangements for data processing equipment, office equipment, office space and land.

Operating leases, which are charged to operating expense, consist principally of leases of office space and facilities, land, railroad rights of way and a wide variety of equipment.  The future minimum lease payments under these operating leases are estimated to be as follows:

	(In Thousands)
2011		13,854
2012		7,848	(1)
2013		1,992
2014		1,492
2015		1,442
2016 - after		36,893
Total		63,521

 (1) Lease for office space in the building located at 157 Church Street, New Haven, Connecticut expires in June 2012.

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Rental payments charged to operating expenses in 2010 and 2009 were as follows:

	Year Ended December 31,
	2010		2009
	(In Thousands)
Rental payments	$	13,766	$	13,588
Less: Sublease rental payments received		1,120		1,125
Rental payments charged to operating expenses	$	12,646	$	12,463

 (J)  COMMITMENTS AND CONTINGENCIES

Connecticut Yankee Atomic Power Company

UI has a 9.5% stock ownership share in the Connecticut Yankee Atomic Power Company (Connecticut Yankee), the carrying value of which was $0.2 million as of December 31, 2010.  In 1996, the Board of Directors of Connecticut Yankee voted unanimously to retire the Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial operation.  Connecticut Yankee updates the cost of its remaining decommissioning activity, which consists primarily of ground water monitoring and nuclear fuel storage, at least annually, and more often as needed, and provides UI with a projected recovery schedule depicting annual costs expected to be billed to UI, including a return on investment over the term of the projected recovery period.  The present value of these costs is calculated using UI’s weighted-average cost of capital and, after consideration of recoverability, recorded as a Connecticut Yankee Contract Obligation and a corresponding regulatory asset.  At December 31, 2010, UI has regulatory approval to recover in future rates (through the CTA) its $17.2 million regulatory asset for Connecticut Yankee over a term ending in 2015.

DOE Spent Fuel Litigation

In the Nuclear Waste Policy Act of 1982, Congress provided for the United States Department of Energy (DOE) to dispose of spent nuclear fuel and other high-level waste (hereinafter Nuclear Waste) from nuclear generating plants.  In 1983, Connecticut Yankee and the DOE entered into a standard disposal contract mandated by the Act which required the DOE to begin disposing of Connecticut Yankee’s Nuclear Waste by the end of January 1998.

In 1998, Connecticut Yankee filed claims in the United States Court of Federal Claims seeking damages resulting from the breach of the 1983 contracts by the DOE.  In September 2010, the Court issued its Decision in the remanded case and awarded Connecticut Yankee damages of $39.7 million for its spent fuel-related costs through 2001.  On November 8, 2010, the DOE appealed the decision to the United States Court of Appeals for the Federal Circuit and on November 19, 2010 Connecticut Yankee filed a notice of cross-appeal.  UI’s 9.5% ownership share would result in a payment of approximately $3.8 million which, if awarded, would be refunded to customers.

In December 2007, Connecticut Yankee filed a second set of complaints against the government seeking unspecified damages incurred since January 1, 2002 for the DOE’s failure to remove Connecticut Yankee’s spent fuel.  In July 2009, Connecticut Yankee provided the government with a second set of damage claims totaling approximately $135 million for damages incurred from January 1, 2002 through December 31, 2008.  UI’s 9.5% ownership share would result in a payment of approximately $12.8 million which, if awarded, would be refunded to customers.  As an interim measure until the DOE complies with its contractual obligation to dispose of Connecticut Yankee’s spent fuel, Connecticut Yankee constructed an ISFSI, utilizing dry-cask storage, on the site of the Connecticut Yankee Unit and completed the transfer of its Nuclear Waste to the ISFSI in 2005.

Hydro-Quebec

UI is a participant in the Hydro-Quebec (HQ) transmission tie facility linking New England and Quebec, Canada.  UI has a 5.45% participating share in this facility, which has a maximum 2000-megawatt equivalent generation capacity value.  In April 1991, UI furnished a guarantee in the amount of $11.7 million, for its participating share of the debt financing for one phase of this facility.  The amount of this guarantee, which expires in August 2015, is reduced monthly, proportionate with principal paid on the underlying debt.  As of December 31, 2010, the amount of UI’s guarantee for this debt totaled approximately $1.4 million.

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Environmental Concerns

In complying with existing environmental statutes and regulations and further developments in areas of environmental concern, including legislation and studies in the fields of water quality, hazardous waste handling and disposal, toxic substances, climate change and electric and magnetic fields, UI may incur substantial capital expenditures for equipment modifications and additions, monitoring equipment and recording  devices, and it may incur additional operating expenses.  The total amount of these expenditures is not now determinable.  Environmental damage claims may also arise from the operations of UI.  Significant environmental issues known to UI at this time are described below.

Site Decontamination, Demolition and Remediation Costs

By letter dated November 30, 2010, the EPA made inquiry of UI regarding the storage of PCB materials from the time they were brought to UI’s Shelton, CT facility from the field until their shipment to an authorized disposal facility, from 2006 through June of 2010, and the maintenance of an annual document log in connection with the storage.  On January 14, 2011, the Company filed its response to this inquiry with EPA, setting forth the details of the Company’s PCB management policy and providing annual summaries for the referenced years.  On February 8, 2011, UI received an EPA subpoena requesting additional information concerning the annual summaries provided.  UI has responded to this subpoena.  At this time, UI cannot assess the potential financial impact, if any, of this inquiry.   As such, as of December 31, 2010, no liability related to this matter has been recorded.

In June 2006, UI executed an agreement with the City of Bridgeport and its Redevelopment Authority (the City) for the transfer of title of UI’s Steel Point property to the City.  Pursuant to a Memorandum of Understanding (MOU) among UI, the City of Bridgeport, and the City’s selected developer for the property, the City and developer released UI from any further liability with respect to the Steel Point property after title transferred, and the City and/or developer has indemnified UI for environmental matters related to the Steel Point property.  The Steel Point property includes the land up to the bulkhead.  The MOU provides that there is no indemnity for liability related to contaminated harbor sediments.  UI is not aware of any such claims.  UI would seek to recover any uninsured costs related to such sediments that are UI’s responsibility, to the extent incurred, through the CTA, in accordance with the ratemaking treatment approved in the DPUC’s July 2006 decision.

A site on the Mill River in New Haven was conveyed by UI in 2000 to an unaffiliated entity, Quinnipiac Energy LLC (QE), reserving to UI permanent easements for the operation of its transmission facilities on the site.  At the time of the sale, a fund of approximately $1.9 million, an amount equal to the then-current estimate for remediation, was placed in escrow for purposes of bringing soil and groundwater on the site into compliance with applicable environmental laws.  Approximately $0.1 million of the escrow fund remains unexpended.  QE has since sold the property to Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat).  UI is unaware of what agreement was reached between QE and Evergreen Power and Asnat regarding future environmental liability or what remediation activity remains to be undertaken at the site.  UI could be required by applicable environmental laws to finish remediating any subsurface contamination at the site if it is determined that QE and/or Evergreen Power and Asnat have not completed the appropriate environmental remediation at the site.  UI has not updated the original $1.9 million remediation estimate, and does not have specific knowledge of any remediation work done, or remaining to be done on behalf of QE or any subsequent owner.  In July 2008, Evergreen Power and Asnat submitted a claim to UI seeking compensation for environmental remediation on the property, including the existing building which remains on the site.   UI cannot presently assess the potential financial impact, if any, of this claim.  As such, as of December 31, 2010, no liability related to this claim has been recorded.

In April 1999, UI completed the sale of its Bridgeport Harbor Station and New Haven Harbor Station generating plants in compliance with Connecticut’s electric utility industry restructuring legislation.  With respect to the portion of the New Haven Harbor Station site that UI retained, UI has performed an additional environmental analysis, indicating that approximately $3.2 million in remediation expenses will be incurred.  Actual remediation costs may be higher or lower than what is currently estimated.  The required remediation is virtually all on transmission-related property and UI has accrued these estimated expenses, which were recovered in transmission rates.

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From 1961 to 1976, UI owned a parcel of property in Derby, Connecticut, on which it operated an oil-fired electric generating unit.  For several years, the Connecticut Department of Environmental Protection (CDEP) has been monitoring and remediating a migration of fuel oil contamination from a neighboring parcel of property into the adjacent Housatonic River.  Based on its own investigation to date, UI believes it has no responsibility for this contamination.  If regulatory agencies determine that UI is responsible for the cost of these remediation activities, UI may incur substantial costs, no estimate of which is currently available.

Middletown/Norwalk Transmission Project

The general contractor and two subcontractors responsible for civil construction work in connection with the installation of UI’s portion of the Middletown/Norwalk Transmission Project’s underground electric cable system have filed lawsuits seeking payment for change order requests for approximately $34.5 million, plus interest and costs.  UI intends to defend the litigation.  To the extent that UI is required to satisfy any of the change order requests, UI would seek recovery through its transmission revenue requirement.

GenConn

The former general contractor responsible for the construction at the GenConn Devon facility has submitted change order requests totaling approximately $8.5 million and has asserted a delay and impact claim against GenConn Devon in the amount of approximately $16.9 million.  GenConn Devon is reviewing a report prepared on the contractor's behalf with respect to the delay claim, and will be continuing its review of the change order requests after reviewing the report.  The former general contractor has also claimed approximately $4.9 million as a final payment with respect to its prior work as general contractor for the GenConn Middletown facility.  GenConn Middletown disputes this claim, and the parties have agreed to non-binding mediation of the claim relating to GenConn Middletown.  To the extent that GenConn is required to pay all or a portion of these claims, as with other capital construction expenditures, GenConn would seek, and expect to recover, associated costs through its annual regulatory proceeding.  To the extent that there is any financial impact on GenConn’s financial statements, the effect on UI’s Financial Statements will be reflected in the carrying value of its 50% ownership position in GenConn and through “Income (Loss) from Equity Investments” in the Statement of Income.

On September 28, 2010, UIL Holdings entered into a Sponsor Guaranty and Payment Agreement in favor of the Royal Bank of Scotland PLC, as Administrative Agent under the Project Financing arrangement, whereby UIL Holdings guarantees to pay an amount up to $6 million in respect of amounts related to the former general contractor’s claims and litigation expenses as they relate to such claims described above.  Given the assessment of this claim as described above, no liability has been recorded as of December 31, 2010.

Purchase Obligations

As of December 31, 2010, UI had $67.3 million of purchase commitments representing contractual obligations for material and services on order but not yet delivered.

 (K) FAIR VALUE MEASUREMENTS

UI utilizes an income approach valuation technique to value the majority of its assets and liabilities measured and reported at fair value.  As required by ASC 820, financial assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the fair value measurement.  UI’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables set forth UI’s financial assets and liabilities, other than pension benefits and OPEB, which were accounted for at fair value on a recurring basis as of December 31, 2010 and December 31, 2009.

- 38 -

	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total
December 31, 2010	(In Thousands)
Assets:
Derivative assets	$	-	$	-	$	33,831		$	33,831
Deferred Compensation Plan		2,320		-		-			2,320
Supplemental retirement benefit trust life insurance policies (Note G)		5,665		-		-			5,665
	$	7,985	$	-	$	33,831		$	41,816
Liabilities:
Derivative liabilities	$	-	$	-	$	142,806		$	142,806
Net fair value assets/(liabilities), December 31, 2010	$	7,985	$	-	$	(108,975	)	$	(100,990	)
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total
December 31, 2009	(In Thousands)
Assets:
Derivative assets	$	-	$	-	$	30,694		$	30,694
Deferred Compensation Plan		2,073		-		-			2,073
Supplemental retirement benefit trust life insurance policies (Note G)		5,071		-		-			5,071
	$	7,144	$	-	$	30,694		$	37,838
Liabilities:
Derivative liabilities	$	-	$	-	$	162,093		$	162,093
Net fair value assets/(liabilities), December 31, 2009	$	7,144	$	-	$	(131,399	)	$	(124,255	)

The determination of fair value of the derivative assets and liabilities, which primarily consist of contracts for differences, was based on a probability-based expected cash flow analysis that was discounted at the December 31, 2010 or December 31, 2009 risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates.  Certain management assumptions were required, including development of pricing that extended over the term of the contracts.  In addition, UI performed an assessment of risks related to obtaining regulatory, legal and siting approvals, as well as obtaining financing resources and ultimately attaining commercial operation. The DPUC has determined that changes in fair value associated with the contracts for differences are fully recoverable.  As a result, such changes have no impact on UI’s net income.

The fair value of the noncurrent investments available for sale is determined using quoted market prices in active markets for identical assets.  The investments primarily consist of money market funds.

UI participates in the UIL Deferred Compensation Plan (DCP), directors, named executive officers and certain other executives may elect to defer certain elements of compensation.  Participants in the DCP are permitted to direct investments of their elective deferral accounts into ‘deemed’ investments consisting of non-publicly traded mutual funds available through variable insurance products, and Company common stock equivalents.  These investments, which are actively traded in sufficient frequency and volume to provide pricing information on an ongoing basis, are marked-to-market in accordance with ASC 815 based upon such pricing information.

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The following tables set forth a reconciliation of changes in the fair value of the assets and liabilities above that are classified as Level 3 in the fair value hierarchy for the twelve month periods ended December 31, 2010 and 2009.  The change in a probability assumption of in an expected cash flow analysis resulted in the reduction of UI’s projected derivative liability relating to one of UI’s CfDs.  The reduction of this derivative liability was the primary reason for the increase in the net fair value of the net derivative assets/(liabilities) during the twelve month period ended December 31, 2010.

	Year Ended
	December 31, 2010
	(In Thousands)
Net derivative assets/(liabilities), December 31, 2009	$	(131,399	)
Unrealized gains and (losses), net		22,424
Net derivative assets/(liabilities), December 31, 2010	$	(108,975	)
Change in unrealized gains (losses), net relating to net derivative assets/(liabilities), still held as of December 31, 2010	$	22,424

	Year Ended
	December 31, 2009
	(In Thousands)
Net derivative assets/(liabilities), January 1, 2009	$	(83,493	)
Unrealized gains and (losses), net		(47,906	)
Net derivative assets/(liabilities), December 31, 2009	$	(131,399	)
Change in unrealized gains (losses), net relating to net derivative assets/(liabilities), still held as of December 31, 2009	$	(47,906	)

The following table sets forth a reconciliation of changes in the net regulatory asset/(liability) balances that were established to recover any unrealized gains/(losses) associated with the contracts for differences for the years ended December 31, 2010 and 2009.  The amounts offset the net contract for differences liabilities included in the derivative liabilities detailed above.

- 40 -

	Year Ended
	(In Thousands)
Net regulatory assets/(liabilities), December 31, 2009	$	131,399
Unrealized (gains) and losses, net		(22,424	)
Net regulatory assets/(liabilities), December 31, 2010	$	108,975
	Year Ended
	December 31, 2009
	(In Thousands)
Net regulatory assets/(liabilities), January 1, 2009	$	83,493
Unrealized (gains) and losses, net		47,906
Net regulatory assets/(liabilities), December 31, 2009	$	131,399

The following tables set forth the fair values of UI‘s pension and OPEB assets that were accounted for at fair value on a recurring basis as of December 31, 2010 and 2009.

	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
December 31, 2010	(In Thousands)
Pension assets
Mutual funds	$	244,700	$	-	$	-	$	244,700
Hedge fund		-		-		390		390
		244,700		-		390		245,090
OPEB assets
Mutual funds		22,287		-		-		22,287
		22,287		-		-		22,287
Fair value of plan assets, December 31, 2010	$	266,987	$	-	$	390	$	267,377
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
December 31, 2009	(In Thousands)
Pension assets (Note G)
Mutual funds	$	227,832	$	-	$	-	$	227,832
Hedge fund		-		-		3,476		3,476
		227,832		-		3,476		231,308
OPEB assets (Note G)
Mutual funds		22,194		-		-		22,194
		22,194		-		-		22,194
Fair value of plan assets, December 31, 2009	$	250,026	$	-	$	3,476	$	253,502

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The determination of fair value of the Level 1 pension and OPEB assets was based on quoted prices, as of December 31, 2010 and 2009, in the active markets for the various funds within which the assets are held.  The determination of fair value of the Level 3 pension assets was based on the Net Asset Value (NAV) provided by the managers of the underlying fund investments.  The NAV provided by the managers typically reflect the fair value of each underlying fund investment, including unrealized gains and losses.  Changes in the fair value of pension benefits and OPEB are accounted for in accordance with ASC 715 Compensation – Retirement Benefits as discussed in Note (G) Pension and Other Benefits.

The following tables set forth a reconciliation of changes in the fair value of the assets above that are classified as Level 3 in the fair value hierarchy for the twelve month periods ended December 31, 2010 and 2009.

	Year Ended
	December 31, 2010
	(In Thousands)
Pension assets-Level 3, December 31, 2009	$	3,476
Unrealized gains and (losses), net		(919	)
Realized gains and (losses), net		(835	)
Purchases, sales, issuances, and settlements		(1,332	)
Pension assets-Level 3, December 31, 2010	$	390
Change in unrealized gains (losses), net relating to pension assets still held as of December 31, 2010	$	(919	)
	Year Ended
	December 31, 2009
	(In Thousands)
Pension assets-Level 3, January 1, 2009	$	9,684
Unrealized gains and (losses), net		(416	)
Realized gains and (losses), net		(1,380	)
Purchases, sales, issuances, and settlements		(4,412	)
Pension assets-Level 3, December 31, 2009	$	3,476
Change in unrealized gains (losses), net relating to pension assets still held as of December 31, 2009	$	(416	)

42

EX-99.2

EXHIBIT 99.2

Connecticut Natural Gas Corporation

Financial Statements

For the period November 17, 2010 to December 31, 2010 (Successor),

the period January 1, 2010 to November 16, 2010 (Predecessor), and the

Year Ended December 31, 2009 (Predecessor)

Connecticut Natural Gas Corporation

Index

 Page(s)

Financial Statements:

Report of Independent Auditors
Statements of Operations (1)	1
Statements of Comprehensive Income (1)	1
Balance Sheets at December 31, 2010 (Successor) and 2009 (Predecessor)	2 – 3
Statements of Cash Flows (1)	4
Statements of Changes in Common Stock Equity (1)	5
Notes to Financial Statements	6 – 32

(1) For the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor)

Connecticut Natural Gas Corporation

Statements of Operations (1)

	Successor						Predecessor
	Period  November 17,  to December  31, 2010			Period  January 1, to  November 16, 2010			Year Ended  December 31,  2009
(Thousands)
Operating Revenues
Sales and services	$	64,227		$	296,058		$	351,214
Operating Expenses
Natural gas purchased		40,180			181,030			210,804
Other operating expenses		5,738			47,843			72,011
Maintenance		1,131			6,810			7,635
Goodwill impairment		-			90,923			-
Depreciation and amortization		2,843			21,066			22,441
Other taxes		3,591			18,012			22,328
Total Operating Expenses		53,483			365,684			335,219
Operating Income (Loss)		10,744			(69,626	)		15,995
Other (Income)		(345	)		(4,928	)		(2,657	)
Other Deductions		208			450			837
Interest Charges, Net		1,553			10,579			12,578
Income (Loss) Before Income Taxes		9,328			(75,727	)		5,237
Income Taxes		3,457			4,349			1,507
Net Income (Loss)		5,871			(80,076	)		3,730
Less: Preferred Stock Dividends		3			49			39
Earnings (Loss) Available for Common Stock	$	5,868		$	(80,125	)	$	3,691

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

Connecticut Natural Gas Corporation

Statements of Comprehensive Income (1)

	Successor					Predecessor
	Period  November 17,  to December  31, 2010		Period January 1, to  November 16, 2010			Year Ended  December 31,  2009
(Thousands)
Net Income (Loss)	$	5,871	$	(80,076	)	$	3,730
Other Comprehensive Income (Loss), Net of Tax		17		(11	)		1,064
Comprehensive Income (Loss)	$	5,888	$	(80,087	)	$	4,794

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

(1) For the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor)

1

Connecticut Natural Gas Corporation

Balance Sheets

	Successor		Predecessor
December 31,	2010		2009
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$	49,520	$	1,747
Accounts receivable and unbilled revenues, net		70,881		66,369
Accounts receivable from affiliate		964		637
Natural gas in storage, at average cost		54,630		69,551
Deferred income taxes		1,625		-
Prepayments and other current assets		6,463		27,600
Total Current Assets		184,083		165,904
Utility Plant, at Original Cost
Natural gas		634,481		629,365
Less accumulated depreciation		216,886		212,446
Net Utility Plant in Service		417,595		416,919
Construction work in progress		428		502
Total Utility Plant		418,023		417,421
Other Property and Investments		1,920		6,525
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes		3,958		6,384
Deferred income taxes		5,859		7,947
Deferred purchased gas costs		8,408		15,623
Pension and other postretirement benefits		79,895		87,715
Other		56,372		38,529
Total regulatory assets		154,492		156,198
Other assets
Goodwill		115,068		218,630
Other		2,750		4,427
Total other assets		117,818		223,057
Total Regulatory and Other Assets		272,310		379,255
Total Assets	$	876,336	$	969,105

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

2

Connecticut Natural Gas Corporation

Balance Sheets

	Successor		Predecessor
December 31,	2010		2009
(Thousands, except shares)
Liabilities
Current Liabilities
Current portion of long-term debt	$	3,915		-
Accounts payable and accrued liabilities		8,252	$	3,761
Account payable, natural gas purchased		30,623		31,852
Accounts payable to affiliates		1,161		1,389
Interest accrued		2,738		2,634
Taxes accrued		9,462		8,515
Other		12,781		13,332
Total Current Liabilities		68,932		61,483
Regulatory and Other Liabilities
Regulatory liabilities
Pension and other postretirement benefits		10,404		12,333
Accrued removal obligations		112,548		108,155
Other		26,573		37,546
Total regulatory liabilities		149,525		158,034
Other liabilities
Deferred income taxes		13,862		89,733
Pension and other postretirement benefits		77,886		83,369
Asset retirement obligations		6,769		6,921
Other		4,862		8,641
Total other liabilities		103,379		188,664
Total Regulatory and Other Liabilities		252,904		346,698
Long-term debt		163,805		150,000
Total Liabilities		485,641		558,181
Commitments and Contingencies
Preferred Stock
Preferred stock		750		750
Common Stock Equity  Common stock ($3.125 par value, 20,000,000 shares    authorized, 10,634,436 shares outstanding for 2010    and 2009)		33,233		33,233
Capital in excess of par value		350,827		335,814
Retained earnings		5,868		41,526
Accumulated other comprehensive income (loss)		17		(399	)
Total Common Stock Equity		389,945		410,174
Total Liabilities and Equity	$	876,336	$	969,105

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

3

Connecticut Natural Gas Corporation

Statements of Cash Flows

	Successor			Predecessor
	Period November 17, to December 31, 2010			Period January 1, to November 16, 2010			Year Ended December 31, 2009
(Thousands)
Operating Activities
Net income (loss)	$	5,871		$	(80,076	)	$	3,730
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization		3,316			21,650			23,389
Amortization of regulatory and other assets and liabilities, net		(2,508	)		(7,277	)		(20,837	)
Deferred income taxes and investment tax credits, net		1,598			(388	)		20,034
Pension expense		312			5,998			4,955
Goodwill impairment		-			90,923			-
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net		(24,150	)		19,312			31,827
Inventory		11,746			2,967			37,534
Prepayments and other current assets		800			(1,271	)		(1,522	)
Accounts payable and accrued liabilities		3,950			(1,140	)		(22,927	)
Interest accrued		726			(622	)		(55	)
Taxes accrued		5,527			16,092			(23,589	)
Other current liabilities		(1,447	)		1,940			1,874
Changes in other assets		(7,464	)		(5,758	)		(10,728	)
Changes in other liabilities
Nonfirm margin sharing		966			4,848			15,839
Other		2,539			6,629			2,364
Net Cash Provided by Operating Activities		1,782			73,827			61,888
Investing Activities
Utility plant additions		(2,053	)		(18,717	)		(16,909	)
Investments, net		-			3,986			10,434
Net Cash Used in Investing Activities		(2,053	)		(14,731	)		(6,475	)
Financing Activities
Long-term note issuance		-			-			20,000
Notes payable three months or less, net		-			-			(67,650	)
Dividends paid on common and preferred stocks		(3	)		(11,049	)		(11,039	)
Net Cash Used in Financing Activities		(3	)		(11,049	)		(58,689	)
Net (Decrease) Increase in Cash and Cash Equivalents		(274	)		48,047			(3,276	)
Cash and Cash Equivalents, Beginning of Period		49,794			1,747			5,023
Cash and Cash Equivalents, End of Period	$	49,520		$	49,794		$	1,747

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

4

Connecticut Natural Gas Corporation
Statements of Changes in Common Stock Equity (Predecessor)
(Thousands, except shares)	Common Stock Outstanding  $3.125 Par Value				Capital in  Excess of		Retained  Earnings			Accumulated  Other  Comprehensive
		Shares		Amount		Par Value		(Deficit)			Income (Loss)			Total
Balance, January 1, 2009		10,634,436	$	33,233	$	335,814	$	48,835		$	(1,463	)	$	416,419
Net income								3,730						3,730
Other comprehensive income, net of tax											1,064			1,064
Comprehensive income														4,794
Dividends – common stock								(11,000	)					(11,000	)
Dividends – preferred stock								(39	)					(39	)
Balance, December 31, 2009		10,634,436		33,233		335,814		41,526			(399	)		410,174
Net (loss)								(80,076	)					(80,076	)
Other comprehensive income, net of tax											(11	)		(11	)
Comprehensive income														(80,087	)
Dividends – common stock								(11,000	)					(11,000	)
Dividends – preferred stock								(49	)					(49	)
Balance, November 16, 2010		10,634,436	$	33,233	$	335,814	$	(49,599	)	$	(410	)	$	319,038

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

(Successor)
(Thousands, except shares)	Common Stock Outstanding $3.125 Par Value				Capital in Excess of		Retained			Accumulated Other Comprehensive
		Shares		Amount		Par Value		Earnings			(Loss) Income		Total
Balance, November 17, 2010		10,634,436	$	33,233	$	350,827		-			-	$	384,060
Net income							$	5,871					5,871
Other comprehensive income, net of tax											17		17
Comprehensive income													5,888
Dividends – preferred stock								(3	)				(3	)
Balance, December 31, 2010		10,634,436	$	33,233	$	350,827	$	5,868		$	17	$	389,945

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

5

Notes to Financial Statements

Connecticut Natural Gas Corporation

Note 1. Significant Accounting Policies

Background: Connecticut Natural Gas Corporation (CNG, the company, we, our, us) 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 is the principal operating utility of CTG Resources, Inc. (CTG), a wholly-owned subsidiary of UIL Holdings Corporation (UIL Holdings). On November 17, 2010, UIL Holdings purchased CTG from Iberdrola USA, Inc. (Iberdrola USA) a wholly-owned subsidiary of Iberdrola S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain. We operate under the authority of the Connecticut Department of Public Utility Control (DPUC) in Connecticut and are also subject to regulation by the Federal Energy Regulatory Commission (FERC).

We have evaluated events or transactions that occurred after December 31, 2010, for inclusion in these financial statements through March 31, 2011, which is the date these financial statements were available to be issued.

During the preparation of our 2010 financial statements, management determined that our previously issued financial statements for the year ended December 31, 2009, included errors related to the recording of certain adjustments including (1) the overstatement of unbilled revenues and accounts receivable in the amount of approximately $1.4 million and (2) the overstatement of regulatory assets and the understatement of expense in the amount of approximately $984,000.  Management has concluded that these errors did not have a material impact on the financial statements for the year ended December 31, 2009, and therefore the corrections were recorded within financial statements for the predecessor period ended November 16, 2010.

If the financial statements for 2009 were revised to reflect the errors including the two identified items above, income before income taxes for the year ended December 31, 2009, would have been decreased to approximately $4,089,000 and net income would have been decreased to approximately $2,808,000.

Accounts receivable: Accounts receivable include unbilled revenues of $19 million at December 31, 2010, and $20 million at December 31, 2009, and are shown net of an allowance for doubtful accounts of $4 million at December 31, 2010, and $3 million December 31, 2009. Accounts receivable do not bear interest, although late fees may be assessed. Bad debt expense for the predecessor period was $12 million for January 1, to November 16, 2010, $8 million for the successor period November 17, to December 31, 2010, and $11 million for 2009.

Unbilled revenues represent estimates of receivables for energy 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 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 and

6

Notes to Financial Statements

Connecticut Natural Gas Corporation

customer receivables, which are inherently uncertain and susceptible to change from period to period, could significantly affect the allowance for doubtful accounts estimates. During the predecessor period January 1 to November 16, 2010, we recorded an increase in the allowance for doubtful accounts of $1 million because we no longer consider customer security deposits when we determine the amount of our allowance for doubtful accounts.

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 $7 million at December 31, 2010 and 2009. The ARO consists primarily of obligations related to removal or retirement of: asbestos, 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.

Accrued removal obligations: We meet the requirements concerning accounting for 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 a maturity date of three months or less when acquired to be cash equivalents and those investments are included in cash and cash equivalents.

	Successor					Predecessor
Supplemental Disclosure of Cash Flows Information	Period  November 17,  to December  31, 2010		Period  January 1, to  November  16, 2010			Year Ended  December  31, 2009
(Thousands)
Cash paid (received) during the period:
Interest, net of amounts capitalized	$	779	$	10,732		$	10,505
Income taxes, net of cash paid		-	$	(16,158	)	$	3,342

We have decreased utility plant additions by $224 thousand for amounts payable as of December 31, 2010.

Depreciation and amortization: We determine depreciation expense 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: gas production property – 35 years, gas storage property – 80 years, distribution property – 53 years, and other property – 33 years. Our depreciation accruals were equivalent to 4% of average depreciable property for 2010 and 2009.

7

Notes to Financial Statements

Connecticut Natural Gas Corporation

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.

Goodwill: We perform an annual goodwill impairment test during the third quarter 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 a potential impairment of goodwill requires a two step process. Step one of the impairment test involves comparing the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of a reporting unit exceeds its fair value, step two must be performed to determine the amount, if any, of goodwill impairment loss. If the carrying value is less than the fair value, further testing for 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.

In performing the annual impairment test, for purposes of the step one analysis, we base the determination of the fair value of its 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 CNG was greater than its carrying value in 2009.

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.

As a result of Iberdrola USA’s decision in May 2010 to sell CNG we updated our impairment test of goodwill in accordance with the two step process described above. We determined that the carrying value of CNG exceeded the purchase price agreed to by UIL Holdings, resulting in a goodwill impairment of $91 million. (See Note 2.)

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

Fair value measurements: The FASB has issued a number of new standards related to fair value measurements. In April 2009 the FASB issued two new standards related to fair value measurements, which we began applying effective April 1, 2009:

8

Notes to Financial Statements

Connecticut Natural Gas Corporation

·   One of the new standards provides guidance for determining fair value when the volume and level of activity for an asset or liability have significantly decreased and for identifying transactions that are not orderly. It provides additional guidance to entities for estimating fair value in accordance with existing requirements when the volume and level of activity for an asset or a liability has significantly decreased. Even in those circumstances, and without considering the valuation technique(s) used, the intention of fair value measurement does not change. The new standard also provides guidance for identifying circumstances that indicate a transaction is not orderly. In addition, it amends the disclosures in connection with fair value measurements to require disclosure in interim and annual periods about the inputs and valuation techniques used to measure fair value as well as a discussion of any changes in them during the period; and to require disclosures concerning debt and equity securities according to major security types.

·   The other new standard provides amended guidance concerning the recognition and presentation of other-than-temporary impairments. It amends the guidance in U.S. generally accepted accounting principles for other-than-temporary impairment of debt securities (but not equity securities) to make it more operational and to improve the financial statement presentation and disclosure of other-than-temporary impairments on debt and equity securities.

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.

In January 2010 the FASB issued amendments to improve disclosures about fair value measurements. New disclosures that are or will be required include: 1) details of transfers in and out of Level 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 new standards related to fair value measurements had no effect on our financial position, results of operation or cash flows. Our adoption of the amendments concerning Level 3 roll forward activity effective for fiscal years beginning on or after January 1, 2011, and interim periods within those fiscal years, will not affect our results of operation, financial position or cash flows.

9

Notes to Financial Statements

Connecticut Natural Gas Corporation

Other (Income) and Other Deductions:

	Successor						Predecessor
	Period November 17, to December 31, 2010			Period January 1, to November 16, 2010			Year Ended December 31, 2009
(Thousands)
Interest and dividend income	$	(46	)	$	(64	)	$	(335	)
Carrying costs on regulatory assets		(298	)		(1,485	)		(1,104	)
Life insurance		-			(252	)		(1,210	)
Gain on energy risk contracts		-			(3,000	)		-
Miscellaneous		(1	)		(127	)		(8	)
Total other (income)	$	(345	)	$	(4,928	)	$	(2,657	)
Civic donations	$	30		$	53		$	87
Losses on energy risk contracts		132			298			443
Miscellaneous		46			99			307
Total other deductions	$	208		$	450		$	837

Regulatory assets and 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.

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 plan. Amortization of total regulatory liabilities net of amortization of total regulatory assets was $3 million for the successor period November 17, to December 31, 2010, and for the predecessor periods was $7 million for January 1, to November 16, 2010, and $21 million for 2009.

10

Notes to Financial Statements

Connecticut Natural Gas Corporation

Other regulatory assets and other regulatory liabilities consisted of:

	Successor		Predecessor
December 31,	2010		2009
(Thousands)
Postretirement cost	$	7,868	$	8,839
Low-income program		14,768		16,826
Premium on debt		17,720		-
Other		16,016		12,864
Total other regulatory assets	$	56,372	$	38,529
Nonfirm margin sharing	$	8,217	$	12,478
Asset retirement obligations		5,698		5,137
Pension		7,717		5,787
Deferred gas cost		540		6,408
Tennessee gas pipeline settlement		2,474		2,889
Other		1,927		4,847
Total other regulatory liabilities	$	26,573	$	37,546

Related party transactions: Iberdrola USA Management Corporation provided various administrative and management services to Iberdrola USA's operating utilities, including CNG, 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 CNG by Iberdrola USA Management Corporation for the predecessor periods was approximately $9 million for January 1, to November 16, 2010, and $10 million for 2009.

UIL Holdings provides various administrative and management services to its regulated subsidiaries including CNG.  The cost of services provided to CNG by UIL Holdings was approximately $0.5 million for the period November 17, to December 31, 2010.

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

In addition, we accrue revenue pursuant to the various regulatory provisions to record regulatory assets for revenues that will be collected in the future.

Risk management: We have a purchased gas adjustment clause that allows 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 natural gas for the benefit of customers.

To provide financial protection from declining natural gas sales revenues due to warmer than normal winter temperatures, CNG entered into a weather derivative contract for the winter period November 1, 2010 through April 30, 2011. The structure of the derivative contract allows for CNG to receive or requires CNG to make payments in May 2011 based on the actual Heating Degree Day variance from the purchased put option strike level and/or the written call option

11

Notes to Financial Statements

Connecticut Natural Gas Corporation

strike level. If the actual Heating Degree Days for the November 1, 2010 through April 30, 2011 time period are less than the put option strike level (i.e. warmer than normal temperatures), CNG will receive payment. If the actual Heating Degree Days for the November 1, 2010 through April 30, 2011 time period are more than the call option strike level (i.e. colder than normal temperatures), CNG will make payment. The value of the derivative is carried as a derivative asset on the financial books of record with changes in the value of the derivative asset recorded to the income statement as Other Income/Other Deductions. As of December 31, 2010, derivative assets totaled $347 thousand.

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 for the predecessor periods.

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 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 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 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 evaluations, as considered necessary. Actual results could differ from those estimates.

Note 2. Goodwill

Effective September 16, 2008, Iberdrola S.A purchased all the outstanding stock of Energy East Corporation for $28.50 per share in cash. The accounting guidance for businesscombinations as it relates to push down accounting is addressed in SEC Staff Accounting Bulletin No. 54, Application of "Push Down" Basis of Accounting inFinancial Statements of Subsidiaries Acquired by Purchase. However, in Accounting Standards Codification (ASC) 805-50-S99, the Task Force reached a consensus that push-down accounting is not required for companies that are not SECregistrants. As such, we elected to maintain the books and records on a historical cost basis and the accompanying predecessor financial statements have not been adjusted to reflect purchase accounting by Iberdrola.

12

Notes to Financial Statements

Connecticut Natural Gas Corporation

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. Iberdrola USA’s decision in May 2010 to sell CNG represented a triggering event and we immediately performed an impairment test of our goodwill in accordance with the two step process described in Note 1. We allocated $549 million of the total purchase price to CNG, including estimated working capital adjustments. We determined that the carrying value of CNG exceeded the purchase price agreed to by UIL Holdings, resulting in a goodwill impairment of $91 million.

On November 17, 2010, we recorded an adjustment to goodwill, reducing it by $13 million to reflect the fair value as a result of the purchase by UIL Holdings.

The carrying amount of goodwill as of December 31, 2010 and 2009, is shown in the following table. Goodwill was not adjusted to reflect Iberdrola’s purchase of Energy East and its subsidiaries, including SCG. Goodwill was adjusted to reflect UIL Holdings’ purchase.

	Successor					Predecessor
	Period  November 17,  to December  31, 2010		Period  January 1, to  November 16, 2010			Year Ended December 31, 2009
(Thousands)
Balance at beginning of period
Goodwill	$	115,068	$	218,630		$	218,630
Accumulated impairment losses		-		-			-
Impairment for sale of CNG		-		(90,923	)		-
Balance at end of period
Goodwill		115,068		218,630			218,630
Accumulated impairment losses		-		(90,923	)		-
	$	115,068	$	127,707		$	218,630

Note 3. Income Taxes

	Successor					Predecessor
	Period November 17, to December 31, 2010		Period  January 1, to  November  16, 2010			Year Ended  December  31, 2009
(Thousands)
Current
Federal	$	1,301	$	3,652		$	(14,304	)
State		558		1,085			(4,223	)
Current taxes charged to expense		1,859		4,737			(18,527	)
Deferred
Federal		1,559		71			16,830
State		39		(265	)		3,425
Deferred taxes charged to expense		1,598		(194	)		20,255
Investment tax credit amortization		-		(194	)		(221	)
Total	$	3,457	$	4,349		$	1,507

13

Notes to Financial Statements

Connecticut Natural Gas Corporation

The significant increase in current income tax expense in 2010 compared to 2009 is driven primarily by the effect of filing our 2008 federal and state income tax returns in September 2009. Those filings included a significant one-time tax deduction related to previously capitalized repair costs. The one-time deduction is a temporary difference between book and tax expense and requires normalization, resulting in an offsetting deferred tax expense and is the primary driver of the significant decrease in deferred income tax expense in 2010 as compared to 2009

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

	Successor			Predecessor
	Period  November 17,  to December  31, 2010			Period  January 1, to  November  16, 2010			Year Ended  December  31, 2009
(Thousands)
Tax expense at statutory rate	$	3,265		$	(26,504	)	$	1,833
Depreciation and amortization not normalized		(111	)		1,379			1,891
Investment tax credit amortization					(194	)		(221	)
Removal costs		(79	)		(483	)		(793	)
Medicare subsidy		(13	)		(97	)		(120	)
Goodwill		-			31,623			-
Tax return and audit adjustments		-			(1,165	)		(45	)
State taxes, net of federal benefit		388			533			(519	)
Other, net		7			(743	)		(519	)
Total	$	3,457		$	4,349		$	1,507

Income taxes were $.2 million more than the federal statutory rate of 35% in the successor period 2010, $31.1 million more in the predecessor period 2010 and $.3 million less in 2009.  The successor 2010 effective tax rate was higher than statutory primarily due to recurring flow-through impacts.  The predecessor 2010 effective tax rate was higher than the statutory rate primarily due to goodwill impairment.  The 2009 effective tax rate was lower than the statutory rate primarily due to recurring flow-through impacts including book tax depreciation offset by removal costs.

14

Notes to Financial Statements

Connecticut Natural Gas Corporation

Our deferred tax assets and liabilities consisted of:

	Successor			Predecessor
December 31,	2010			2009
(Thousands)
Current Deferred Income Tax Assets (Liabilities)	$	1,625		$	(344	)
Noncurrent Deferred Income Tax Liabilities (Assets)
Property related	$	(3,538	)	$	80,876
Unfunded future income taxes		1,578			2,546
Accumulated deferred investment tax credits		-			280
Pension		2,323			3,484
Other postretirement benefits		(5,085	)		(5,311	)
Deferred natural gas costs		(689	)		(273	)
Hardship programs		5,889			6,709
Nonfirm margin sharing		(3,276	)		(4,976	)
Rate case		2,953			1,570
Other		7,848			(3,119	)
Total Noncurrent Deferred Income Tax Liabilities		8,003			81,786
Less amounts classified as regulatory assets
Deferred income taxes		(5,859	)		(7,947	)
Noncurrent Deferred Income Tax Liabilities	$	13,862		$	89,733
Deferred tax assets	$	14,213		$	13,679
Deferred tax liabilities		20,591			95,809
Net Accumulated Deferred Income Tax Liabilities	$	6,378		$	82,130

We have no federal tax credit or loss carryforwards and no valuation allowances.

Reconciliation of Gross Income Tax Reserves	2010			2009
(Thousands)
Balance as of January 1	$	2,567			-
Increases for tax positions related to prior years		-		$	2,567
Decrease due to purchase by UIL Holdings		(2,567	)		-
Balance as of December 31		-		$	2,567

There were no gross unrecognized tax benefits as of December 31, 2010.  Gross income tax reserves decreased $2.6 million in 2010 primarily due to the elimination of the property related accumulated deferred income taxes in connection with the sale of CNG to UIL Holdings.

We have been audited through 2005 for federal income taxes. The statute of limitations in Connecticut has expired for all years through 2006. 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.

As a result of the passage of The Small Business Jobs Act in September 2010 and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 in December 2010, certain capital additions qualify for 50% bonus depreciation and 100% expensing, respectively, for tax purposes.  We have elected to apply the 50% bonus and 100% expensing to the additions we have determined qualify for this accelerated tax depreciation.  There is no earnings effect related to this election as the accelerated tax depreciation creates a temporary difference that requires the establishment of a deferred tax liability.

15

Notes to Financial Statements

Connecticut Natural Gas Corporation

Note 4. Long-term Debt

At December 31, 2010 and 2009, our long-term debt was (in thousands):

						Successor		Predecessor
	Interest Rates			Maturity		2010		2009
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		20,000
Total medium-term notes							150,000		150,000
Unamortized premium on debt							17,720		-
							167,720		150,000
Less current portion, included in current liabilities							3,915		-
Total						$	163,805	$	150,000

We have no intercompany collateralizations and have no guarantees to affiliates. None of our debt obligations are guaranteed or secured by our parent or affiliates.

At November 17, 2010, we recorded $18 million of debt premiums with an offset to a regulatory asset to reflect the fair value of the debt at the time of the purchase by UIL Holdings.

At December 31, 2010, other long-term debt, including sinking fund obligations (in thousands) that will become due during the next five years is:

2011	2012	2013	2014	2015
$3,915	$8,802	$43,386	$6,924	$1,751

Note 5. Bank Loans and Other Borrowings

For the successor period we are a joint borrower with the other operating utilities under UIL Holdings in a revolving credit agreement with a group of banks named therein that will expire on November 17, 2014 (the credit facility). Our borrowing limit under the credit facility is $150 million. The credit facility permits borrowings at fluctuating interest rates and also permits borrowings for fixed periods of time specified by each borrower at fixed interest rates determined by the Eurodollar interbank market in London (LIBOR). The credit facility also permits the issuance of letters of credit of up to $50 million.

We draw on our credit facilities to finance working capital needs, to temporarily finance certain refundings and for other corporate purposes. We had no short term debt outstanding at December 31, 2010, and 2009.

16

Notes to Financial Statements

Connecticut Natural Gas Corporation

Note 6. Preferred Stock

At December 31, 2010 and 2009, our cumulative preferred stock was (in thousands):

	Par	Redemption	Shares
	Value	Price	Authorized and	Successor	Predecessor
Series	per Share	per Share	Outstanding(1)	2010	2009
6.00%	$100	$110.00	4,104	$410	$410
8.00% Noncallable	$3.125	-	108,706	340	340
Total				$750	$750

(1) At December 31, 2010 we 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

Lease obligations; CNG has lease arrangements for data processing equipment, office equipment, office space and land. Operating leases, which are charged to operating expense, consist principally of leases of office space and facilities, land, railroad rights of way and a wide variety of equipment. The future minimum lease payments under these operating leases are estimated to be as follows:

(In Thousands)

2011	$527
2012	546
2013	377
2014	205
2015	205
2016 - after	118
Total	$1,978

Note 8. 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. Carrying amounts include related debt premiums.

	Successor				Predecessor
December 31,	2010				2009
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
(Thousands)
Various medium term notes	$	167,720	$	168,300	$	150,000	$	155,942

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

We value our medium term notes 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.

17

Notes to Financial Statements

Connecticut Natural Gas Corporation

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)
Successor 2010 Assets
Noncurrent investments   available for sale	$1,920	$1,920		-
Derivatives	353	347		$6
Total	$2,273	$2,267		$6

Predecessor 2009 Assets
Noncurrent investments   available for sale	$6,525	$6,525	-	-
Derivatives	287	-	-	$287
Total	$6,812	$6,525	-	$287

We had no significant transfers to or from Level 1 and 2 during the year ended December 31, 2010. Our policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that causes a transfer, if any.

Valuation techniques: We measure the fair value of our noncurrent investments available for sale using quoted market prices in active markets for identical assets and include the measurements in Level 1. The investments consist of a money market fund.

We determine the fair value of our fleet fuel derivatives using a proprietary calculation (unobservable to the market) and include the fair value measurements in Level 3. We determine the fair value of fleet fuel derivative contracts 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.

18

Notes to Financial Statements

Connecticut Natural Gas Corporation

Instruments measured at fair value on a recurring basis using significant

unobservable inputs

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivatives, Net
	Successor						Predecessor
	Period  November 17, to  December  31, 2010			Period  January 1, to   November 16, 2010			Year Ended  December 31, 2009
(Thousands)
Beginning balance	$	(17	)	$	287		$	5
Total gains (losses) (realized/unrealized)
Included in earnings		1			(8	)		224
Included in other comprehensive income		22			2,568			58
Transfers into Level 3		-			(2,864	)		-
Ending balance	$	6		$	(17	)	$	287
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at period end.	$	6		$	(17	)	$	287

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
(Thousands)
Total gains (losses) included in earnings for Successor period   November 17, to December 31, 2010	$	1
Predecessor periods   January 1, to November 16, 2010	$	(8	)
Year ended December 31, 2009	$	224

19

Notes to Financial Statements

Connecticut Natural Gas Corporation

Note 9. Accumulated Other Comprehensive (Loss) Income

	Predecessor											Successor
	Balance January 1, 2009			2009 Change		Balance December 31, 2009			January 1 to November 16, 2010 Change			Balance November 17, 2010		November 17,  to December  31, 2010  Change			Balance December 31, 2010
(Thousands)
Net unrealized holding (losses) gains on   investments, net of income tax (expense)   of $(285) for 2009	$	(430	)	$	430>		->			->			->		->			->
Amortization of pension cost for   nonqualified plans, net of income tax   (expense) of $(287) for 2009, $(9) for the   period ending November 16, 2010 and   $(1) for period ending December 31, 2010		(847	)		433>	$	(414	)	$	12>			-	$	5>		$	5>
Unrealized gains on derivatives qualified   as hedges, net of income tax (expense)   of $(44) for 2009, $(85) for period ending   November 16, 2010 and $(9)   for period ending December 31, 2010					67>					129>					13>
Reclassification adjustment for losses   included in net income, net of income   tax (benefit) of $(89) for 2009, $101 for   period ending November 16,   2010 and $.4 for period ending December 31, 2010					134>					(152	)				(1	)
Net unrealized gains (losses) on derivatives qualified as hedges (1)		(186	)		201>		15>			(23	)		-		12>			12>
Accumulated Other Comprehensive (Loss) Income	$	(1,463	)	$	1,064>	$	(399	)	$	(11	)		-	$	17>		$	17>

(1)See Risk management in Note 1.

20

Notes to Financial Statements

Connecticut Natural Gas Corporation

Note 10. 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 a postretirement health care benefits plan covering substantially all of our employees. The health care plan is contributory with participants' contributions adjusted annually.

Obligations and funded status:

	Successor			Predecessor
Pension Benefits	Period  November 17, to  December  31, 2010			Period  January 1, to  November  16, 2010			Year Ended  December  31, 2009
(Thousands)
Change in benefit obligation
Benefit obligation at beginning of period	$	204,079		$	186,802		$	177,754
Service cost		336			3,106			3,162
Interest cost		850			9,891			10,781
Plan amendments		-			-			125
Actuarial (gain) loss		(9,596	)		11,893			3,171
Benefits paid		(714	)		(7,613	)		(8,191	)
Benefit obligation at end of period	$	194,955		$	204,079		$	186,802
Change in plan assets
Fair value of plan assets at beginning of period	$	123,804		$	125,509		$	111,169
Actual return on plan assets		11,493			3,408			22,531
Contributions		-			2,500			-
Benefits paid		(714	)		(7,613	)		(8,191	)
Fair value of plan assets at end of period	$	134,583		$	123,804		$	125,509
Funded status at end of period	$	(60,372	)	$	(80,275	)	$	(61,293	)

21

Notes to Financial Statements

Connecticut Natural Gas Corporation

	Successor			Predecessor
Postretirement Benefits	Period November 17, to  December  31, 2010			Period  January 1, to  November  16, 2010			Year Ended  December  31, 2009
(Thousands)
Change in benefit obligation
Benefit obligation at beginning of period	$	27,823		$	32,060		$	30,953
Service cost		42			282			331
Interest cost		173			1,373			1,834
Plan participants’ contributions		353			1,063			1,403
Transfer due to sale of CNG		55			(1,098	)		-
Actuarial (gain) loss		(654	)		(2,597	)		416
Benefits paid		(366	)		(3,488	)		(3,119	)
Federal subsidy on benefits paid		-			228			242
Benefit obligation at end of period	$	27,426		$	27,823		$	32,060
Change in plan assets
Fair value of plan assets at beginning of period	$	9,948		$	9,989		$	8,712
Actual return on plan assets		(37	)		792			450
Contributions		14			1,364			2,500
Plan participants’ contributions		353			1,063			1,403
Benefits paid		(366	)		(3,488	)		(3,076	)
Federal subsidy on benefits paid		-			228			-
Fair value of plan assets at end of period	$	9,912		$	9,948		$	9,989
Funded status at end of period	$	(17,514	)	$	(17,875	)	$	(22,071	)

Amounts recognized in the balance sheet	Pension Benefits						Postretirement Benefits
	Successor			Predecessor			Successor			Predecessor
December 31,	2010			2009			2010			2009
(Thousands)
Noncurrent liabilities	$	(60,372	)	$	(61,293	)	$	(17,514	)	$	(22,071	)

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 benefit pension and other postretirement plans. Amounts recognized as regulatory assets or regulatory liabilities consist of:

	Pension Benefits					Postretirement Benefits
	Successor			Predecessor		Successor			Predecessor
December 31,	2010			2009		2010			2009
(Thousands)
Net (gain) loss	$	(20,216	)	$	87,002	$	(544	)	$	(750	)
Prior service cost (credit)		-		$	713		-			(177	)

Our accumulated benefit obligation for defined benefit pension plans at December 31 was $183 million for 2010 and $172 million for 2009.

Our postretirement benefits were partially funded at December 31, 2010 and 2009.

22

Notes to Financial Statements

Connecticut Natural Gas Corporation

The projected benefit obligation and accumulated benefit obligation exceeded the fair value of pension plan assets as of December 31, 2010 and 2009. The following table shows the aggregate projected and accumulated benefit obligations and the fair value of plan assets for the underfunded pension plans.

	Successor		Predecessor
December 31	2010		2009
(Thousands)
Projected benefit obligation	$	194,955	$	186,802
Accumulated benefit obligation	$	183,038	$	171,895
Fair value of plan assets	$	134,583	$	125,509

Components of net periodic benefit cost and other amounts

recognized in regulatory assets and regulatory liabilities:

	Successor			Predecessor
Pension Benefits	Period  November 17, to  December  31, 2010			Period  January 1, to  November  16, 2010			Year Ended  December  31, 2009
(Thousands)
Net periodic benefit cost
Service cost	$	336		$	3,106		$	3,162
Interest cost		850			9,891			10,781
Expected return on plan assets		(874	)		(11,478	)		(12,883	)
Amortization of prior service cost		-			193			180
Amortization of net loss		-			4,286			3,715
Net periodic benefit cost	$	312		$	5,998		$	4,955
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities
Net (gain) loss	$	(20,216	)	$	19,964		$	(6,477	)
Amortization of net (loss)		-			(4,286	)		(3,715	)
Current year prior service cost		-			-			125
Amortization of prior service (cost)		-			(193	)		(180	)
Disposition of obligations due to sale		-			(15,485	)		-
Total recognized in regulatory assets   and regulatory liabilities	$	(20,216	)		-		$	(10,247	)
Total recognized in net periodic benefit   cost and regulatory assets and   regulatory  liabilities	$	(19,904	)	$	5,998		$	(5,292	)

23

Notes to Financial Statements

Connecticut Natural Gas Corporation

	Successor			Predecessor
Postretirement Benefits	Period  November 17, to  December  31, 2010			Period  January 1,  to November  16, 2010			Year Ended  December  31, 2009
(Thousands)
Net periodic benefit cost
Service cost	$	43		$	282		$	330
Interest cost		173			1,373			1,834
Expected return on plan assets		(73	)		(512	)		(421	)
Amortization of prior service cost		-			(32	)		73
Amortization of net loss (gain)		-			(180	)		-
Net periodic benefit cost	$	143		$	931		$	1,816
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities
Net (gain) loss	$	(544	)	$	(2,462	)	$	387
Amortization of net (loss) gain		-			32			-
Prior service cost		-			-			-
Amortization of prior service (cost)		-			180			(73	)
Total recognized in regulatory assets and regulatory liabilities	$	(544	)	$	(2,250	)	$	314
Total recognized in net periodic benefit cost and regulatory assets and regulatory liabilities	$	(401	)	$	(1,319	)	$	2,130

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 $8 million for 2010 and $9 million for 2009. 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.

There are no amounts of net gains, losses or prior service costs that are expected to be amortized from regulatory assets or regulatory liabilities into net periodic costs for the fiscal year ending December 31, 2011.

We expect that no pension benefit or postretirement benefit plan assets will be returned to us during the fiscal year ending December 31, 2011.

Weighted-average assumptions used to determine benefit obligations at December 31,	Pension Benefits		Postretirement Benefits
	2010	2009	2010	2009
Discount rate	5.30%	5.80%	5.15%	5.80%
Rate of compensation increase	3.50%	4.00%	N/A	N/A

As of December 31, 2010, we decreased our discount rate from 5.80% to 5.30%. 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.

24

Notes to Financial Statements

Connecticut Natural Gas Corporation

Weighted-average assumptions used to determine net periodic benefit cost for year ended December 31,	Pension Benefits		Postretirement Benefits
	2010	2009	2010	2009
Discount rate	5.80%	6.10%	5.80%	6.10%
Expected return on plan assets	8.75%	8.75%	-	-
Expected long-term return on plan assets -    nontaxable trust	-	-	5.89%	6.00%
Expected long-term return on plan assets -    taxable trust	-	-	-	6.00%
Rate of compensation increase	4.00%	4.00%	N/A	N/A

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’ average remaining service to retirement.

Assumed health care cost trend rates to determine benefit obligations at December 31	2010	2009
Health care cost trend rate assumed for next year	7.8%	8.0%
Rate to which cost trend rate is assumed to decline (the ultimate trend rate)	4.5%	4.5%
Year that the rate reaches the ultimate trend rate	2028	2028

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	$4	$(3)
Effect on postretirement benefit obligation	$394	$(327)

Plan assets:The CNG Pension Plan assets were transferred as part of the acquisition on November 16, 2010. UIL Holdings is responsible for the oversight and management of these assets and has engaged BNY Mellon as the trustee and investment manager to assist in areas of asset allocation and rebalancing, portfolio strategy implementation, and performance monitoring and evaluation. Target allocations are currently being developed for the long-term. In the interim, the assets have been invested in index funds which are approximately 50% equities and 50% fixed income instruments. The governance process is similar to that of the UIL Holdings Pension Plan assets, including oversight by the Retirement Benefits Plans Investment Committee of the Board of Directors in conjunction with management.

Funding policy for the CNG Plan is being developed, but is expected to be similar to the UIL Holdings policy. Asset values as of December 31, 2010 were approximately $135 million.  UIL Holdings did not make any contributions to the Gas Company Plans for the post acquisition period in 2010 and has a minimum funding requirement for 2011 currently estimated at $5 million. Depending upon final actuarial calculations, the 2011 contribution may ultimately range between $12 million and $15 million.

25

Notes to Financial Statements

Connecticut Natural Gas Corporation

The CNG OPEB Plans are funded through a combination of 401(h) accounts and Voluntary Employee Benefit Association Trust (VEBA) accounts. UIL Holdings did not make any contributions to the Plan for the post acquisition period in 2010, nor does it currently plan to make a contribution in 2011.

For 2009, our pension benefits plan assets were held in Iberdrola USA’s 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 diversification 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.

26

Notes to Financial Statements

Connecticut Natural Gas Corporation

The fair values of the pension benefits plan assets at December 31, 2010 and 2009, by asset category  are shown in the following table.

			Fair Value Measurements at December 31, 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)
Successor 2010
Mutual funds	$	134,583	$	134,583		-		-
Total	$	134,583	$	134,583		-		-
Predecessor 2009
Cash and cash equivalents	$	2,130	$	52	$	2,078		-
U.S. government securities		2,763		2,763		-		-
Common stocks		55,706		55,549		157		-
Registered investment companies		6,636		6,636		-		-
Corporate bonds		20,284		-		20,284		-
Preferred stocks		385		385		-		-
Common/collective trusts		19,948		-		3,484	$	16,464
Partnership/joint venture interests		5,194		-		-		5,194
Real estate investments		2,262		-		-		2,262
Other investments, principally   annuity and fixed income		10,201		1,158		1,741		7,302
Total	$	125,509	$	66,543	$	27,744	$	31,222

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

27

Notes to Financial Statements

Connecticut Natural Gas Corporation

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.

UIL Holdings had no Level 3 assets at December 31, 2010.

	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	$	4		$	15,864		$	3,914		$	2,151		$	5,722		$	27,655
Actual return on plan assets:
Relating to assets still held at the reporting date		-			118			118			-			-			236
Relating to assets sold during      the year		-			5,187			179			(894	)		-			4,472
Purchases, sales and settlements		(4	)		(4,705	)		983			1,005			1,580			(1,141	)
Transfers into and/or out of Level 3		-			-			-			-			-			-
Balance, December 31, 2009		-		$	16,464		$	5,194		$	2,262		$	7,302		$	31,222
Transfers into and/or out of Level 3		-		$	(16,464	)	$	(5,194	)	$	(2,262	)	$	(7,302	)	$	(31,222	)
Balance, December 31, 2010		-			-			-			-			-			-

The fair values of other postretirement benefits plan assets at December 31, 2010 and 2009, by asset category are shown in the following table.

			Fair Value Measurements at December 31, 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)
Successor 2010
Money market funds	$	1,720	$	1,720		-		-
Mutual funds, fixed		807		807		-		-
Mutual funds, equity		1,518		1,518		-		-
Total assets measured at     fair value		4,045	$	4,045		-		-
Whole life insurance contract		5,867
Total	$	9,912
Predecessor 2009
Money market funds	$	1,847	$	1,847		-		-
Mutual funds, fixed		256		256		-		-
Mutual funds, equity		428		428		-		-
Other investments		1,622		912	$	378	$	332
Total assets measured at     fair value		4,153	$	3,443	$	378	$	332
Whole life insurance contract		5,836
Total	$	9,989

28

Notes to Financial Statements

Connecticut Natural Gas Corporation

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 UIL Holdings common stock at December 31, 2010, or Iberdrola common stock at December 31, 2009.

Cash Flows

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)
2011	$	8,753	$	2,148	$	275
2012	$	9,415	$	2,173	$	296
2013	$	9,953	$	2,178	$	315
2014	$	10,470	$	2,194	$	330
2015	$	10,895	$	2,165	$	344
2016 – 2020	$	61,802	$	10,038	$	1,969

Note 11. Gas Distribution Rates

Utilities are entitled by Connecticut statute to charge rates that are sufficient to allow them an opportunity to cover their reasonable operating and capital costs, to attract needed capital and to maintain their financial integrity, while also protecting relevant public interests.

In 2008, the DPUC, as required by Connecticut statute, initiated an investigation after CNG reported earning more than one percentage point over its authorized ROE for the previous twelve month period in each of six consecutive months.  In August 2008, the DPUC issued a decision ordering an interim rate decrease for CNG of approximately $15.5 million, or 3.28%, effective August 6, 2008, compared to the rates previously set in the CNG 2006 rate case, and ordered CNG to file a rate case. In January 2009, CNG filed for a rate increase of $16.4 million or approximately 4.4%. The DPUC’s July 2009 decision in the CNG rate proceeding ordered a 4.2% rate decrease, or approximately $16.2 million, compared to the rates set in the 2006 rate case, and reduced CNG’s authorized ROE to 9.31%. CNG appealed the DPUC order to the Connecticut superior court. Pursuant to Connecticut statute, CNG is entitled to collect through a surcharge the differential between the interim rate decrease and the rates finally set after full review. The 2009 DPUC decision ordered rates that were higher than the rates established in the interim rate decrease decision, and accordingly provided for CNG to collect a surcharge from customers. The rates established in the 2009 decision, and certain other orders, have been stayed by stipulation pending the resolution of the appeal. The stipulation stayed CNG’s collection of the surcharge and provides for the continuation of the interim rate decrease amount

29

Notes to Financial Statements

Connecticut Natural Gas Corporation

pending resolution of the appeal. CNG has been accruing the revenues associated with the surcharge for purposes of calculating its earnings. In April 2010, the Connecticut superior court ruled against CNG’s appeal. CNG appealed from the superior court’s dismissal, and that appeal is now pending at the Connecticut supreme court. The stay remains in effect.

CNG has purchased gas adjustment clauses approved by the DPUC, which enables us to pass the reasonably incurred cost of natural gas purchases through to customers. The clauses allow us to recover changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk.

CNG satisfies its natural gas supply requirements through purchases from various producer/suppliers, withdrawals from natural gas storage capacity contracts and winter peaking supplies and resources. We operate diverse portfolios of natural gas supply, firm transportation, gas storage and peaking resources. We contract for such gas resources in our own name for regulatory and other reasons. Our actual incurred natural gas cost is passed through to customers through state regulated purchased gas adjustments mechanisms subject to regulatory review.

The majority of our natural gas supply purchased is acquired at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. We diversify our sources of supply by amount purchased and location and collectively at any time acquire supplies from 10 or more producers of natural gas. We primarily acquire natural gas at various locations in the US Gulf of Mexico region, in the Appalachia region, in Canada and various other locations.

We acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system. Tennessee Gas Pipeline, Algonquin Gas Transmission and Iroquois Gas Transmission interconnect with our distribution system and the other pipelines provide indirect services upstream of the city gates.

The prices and terms and conditions of the firm transportation capacity long-term contracts are regulated by the FERC. Similar to the treatment of gas costs, the actual cost of such contracts is passed through to customers through state regulated purchased gas adjustment mechanisms which are subject to regulatory review. On November 30, 2010, the Tennessee Gas Pipeline Company (Tennessee) filed a FERC rate case proposing significant rate increases across their entire system which runs from south Texas through New England. On December 29, 2010, the FERC issued an order setting the Tennessee rate proceeding for hearing and suspended the proposed rate increase until June 1, 2011, at which time Tennessee has the right to place the rates into effect, subject to refund. The proposed increase would nearly double the fixed cost of reserving pipeline capacity but provide lower variable costs, resulting in a significant net cost increase. We will continue to oppose Tennessee’s proposal and address issues raised by actively participating in the Tennessee FERC proceedings in conjunction with other gas companies and interveners in the Northeastern United States.

We acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer for subsequent withdrawal in the winter. The storage facilities are located in Pennsylvania, New York, West Virginia and Michigan.

Winter peaking resources are attached to the local distribution system through which we own natural gas stored in a liquefied natural gas facility.

30

Notes to Financial Statements

Connecticut Natural Gas Corporation

On March 25, 2011, CNG, together with the Office of Consumer Counsel, filed a motion with the DPUC to reopen CNG rate cases for the purposes of reviewing and approving a settlement agreement. If approved, the settlement agreement would, among other things, resolve all pending issues with respect to the DPUC’s decisions in CNG’s rate cases

Note 12. Environmental

A property located on Columbus Boulevard in Hartford, CT is the former Operations Center and Corporate Headquarters of CNG. The property is also a former MGP site. Except for a portion of the property that houses and is owned by the Hartford Steam Company, known as 60 Columbus Boulevard, and certain other small non-contiguous portions of this site owned by either TEN Companies, Inc. or CNG, most of the original MGP site was taken by the state of Connecticut for the Adriaen’s Landing project. That portion was remediated by the state for the project and, as such, has provided insurance to the company against future risk to CNG associated with additional remediation expenses for that portion of the property that was taken for the Adriaen’s Landing project. CNG remains liable for that portion of the property owned or formerly owned by CNG that was not subject to the taking. Costs associated with the remediation of the site could be significant, but cannot be estimated at this time, and will be subject to a review by the DPUC as to whether those costs are recoverable in rates. UIL Holdings cannot presently estimate the costs of remediation or the likelihood of recoverability. As such, as of December 31, 2010, we have recorded no liability related to this claim.

Note 13. Acquisition

On November 16, 2010, UIL Holdings completed its acquisition (the Acquisition) from Iberdrola USA of CNG.  UIL Holdings accounted for the Acquisition in accordance with ASC 805 “Business Combinations”, whereby the purchase price paid was allocated to tangible assets acquired and liabilities assumed as well as goodwill based upon their fair values as of the closing date.  UIL Holdings has determined that the historical book value of the assets and liabilities of CNG approximates their fair value given the regulation they operate under in Connecticut/Massachusetts.  Additional adjustments to the values of assets and liabilities recognized in the Acquisition may occur as the allocation of the consideration transferred is finalized during 2011.  Under business combination accounting guidance, UIL Holdings has up to one year from the date of the Acquisition to finalize the allocation of consideration transferred.

UIL Holdings “pushed-down” goodwill associated with the Acquisition.  In addition, pre-acquisition retained earnings and accumulated other comprehensive income (loss) balances be “charged” to capital in excess of par value at the time of acquisition.  As a result, CNG recorded $115.1 million of goodwill. Goodwill is calculated as the excess of the purchase price over the net assets acquired and the contributing factors to the amount recorded include expected future cash flows, potential operational synergies, the utilization of technology and cost savings opportunities in the delivery of certain shared administrative and other services.

The estimated fair values of assets acquired and liabilities assumed are based upon the information that was available as of the acquisition date, which management believes provides a reasonable basis for the estimated values.  Management is analyzing additional data necessary to finalize these fair values, which are subject to change.  While such changes could be significant, management does not expect them to be based upon the information provided to date.  The valuation, and thus the purchase price allocation, is expected to be completed as soon as practicable but no later than one year from the acquisition date.

31

Notes to Financial Statements

Connecticut Natural Gas Corporation

The allocated purchase price, the fair value of identifiable assets, and the resulting goodwill are shown in the table below (in millions):

Total identifiable net assets	$	273.9
Goodwill		115.1
Total purchase price, net	$	389.0

As a component of the Acquisition, UIL Holdings and Iberdrola USA have agreed to effect a tax election pursuant to Section 338 (h) (10) of the Internal Revenue Code (338 Election) with respect to the purchase of the stock of CTG. The 338 Election allows UIL Holdings to treat the transaction for tax purposes as if UIL Holdings was purchasing the assets of CTG rather that the stock of each corporation. As a result of the 338 Election, the assets of CTG have newly-established higher tax bases for tax depreciation purposes.

 32

EX-99.3

EXHIBIT 99.3

The Southern Connecticut Gas Company

Financial Statements

For the period November 17, 2010 to December 31, 2010 (Successor),

the period January 1, 2010 to November 16, 2010 (Predecessor), and

the Year Ended December 31, 2009 (Predecessor)

The Southern Connecticut Gas Company

Index

Financial Statements	Page(s)
Report of Independent Auditors
Statements of Operations (1)	1
Statements of Comprehensive Income (1)	1
Balance Sheets at December 31, 2010 (Successor) and 2009 (Predecessor)	2 - 3
Statements of Cash Flows (1)	4
Statements of Changes in Common Stock Equity (1)	5
Notes to Financial Statements	6 – 32

(1) For the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor)

The Southern Connecticut Gas Company

Statements of Operations (1)

	Successor		Predecessor
	Period  November 17,  to December  31, 2010	Period  January 1, to  November 16, 2010	Year Ended   December  31, 2009
(Thousands)
Operating Revenues
Sales and services	$61,736	$292,842	$333,113
Operating Expenses
Natural gas purchased	35,735	158,437	177,489
Other operating expenses	7,861	55,843	73,600
Maintenance	1,172	7,480	8,372
Depreciation and amortization	2,086	15,519	17,241
Goodwill impairment	-	178,885	-
Other taxes	3,192	17,648	23,359
Total Operating Expenses	50,046	433,812	300,061
Operating Income (Loss)	11,690	(140,970)	33,052
Other (Income)	(109)	(452)	(263)
Other Deductions	247	227	1,558
Interest Charges	1,707	14,786	18,892
Income (Loss) Before Income Taxes	9,845	(155,531)	12,865
Income Taxes	4,039	7,936	(1,954)
Net Income (Loss)	$5,806	$(163,467)	$14,819

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

The Southern Connecticut Gas Company

Statements of Comprehensive Income (1)

	Successor		Predecessor
	Period  November 17,  to December  31, 2010	Period  January 1, to  November 16, 2010	Year Ended  December  31, 2009
(Thousands)
Net Income (Loss)	$5,806	$(163,467)	$14,819
Other Comprehensive Income (Loss),   Net of Tax	156	266	701
Comprehensive Income (Loss)	$5,962	$(163,201)	$15,520

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

(1) For the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the Year Ended December 31, 2009 (Predecessor)

1

The Southern Connecticut Gas Company

Balance Sheets

	Successor	Predecessor
December 31,	2010	2009
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$11,542	$17,065
Accounts receivable and unbilled revenues, net	69,684	58,785
Accounts receivable from affiliates	1,256	668
Natural gas in storage, at average cost	48,578	62,873
Materials and supplies, at average cost	883	870
Deferred income taxes	1,919	474
Prepaid taxes	1,853	4,414
Prepayments and other current assets	2,570	5,761
Total Current Assets	138,285	150,910
Utility Plant, at Original Cost
Natural gas	624,151	612,531
Less accumulated depreciation	165,966	159,485
Net Utility Plant in Service	458,185	453,046
Construction work in progress	2,375	868
Total Utility Plant	460,560	453,914
Other Property and Investments	12,422	11,442
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes	21,725	80,222
Environmental remediation costs	2,522	3,022
Deferred purchased gas	14,922	19,051
Low income program	25,906	30,295
Pension and other postretirement benefits	65,937	74,555
Other	63,688	14,276
Total regulatory assets	194,700	221,421
Other assets
Goodwill	132,474	263,645
Other	6,110	7,965
Total other assets	138,584	271,610
Total Regulatory and Other Assets	333,284	493,031
Total Assets	$944,551	$1,109,297

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

2

The Southern Connecticut Gas Company

Balance Sheets

		Successor	Predecessor
December 31,	2010		2009
(Thousands, except shares)
Liabilities
Current Liabilities
Current portion of long-term debt	$33,713		$40,000
Notes payable	7,000		-
Accounts payable and accrued liabilities	14,275		7,654
Accounts payable, natural gas purchased	29,165		25,497
Accounts payable to affiliates	1,047		1,368
Interest accrued	1,788		3,575
Taxes accrued	6,336		8,205
Other	11,863		13,553
Total Current Liabilities	105,187		99,852
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligations	83,377		81,400
Deferred income taxes	22,282		39,854
Pension benefits	10,070		11,398
Other	21,342		27,110
Total regulatory liabilities	137,071		159,762
Other liabilities
Deferred income taxes	5,666		93,710
Pension and other postretirement benefits	61,332		52,756
Asset retirement obligations	10,803		10,609
Other	12,947		16,588
Total other liabilities	90,748		173,663
Total Regulatory and Other Liabilities	227,819		333,425
Long-term debt	190,751		194,000
Total Liabilities	523,757		627,277
Commitments and Contingencies
Common Stock Equity  Common stock ($13.33 par value, 1,876,100 shares    authorized for 1,407,072 shares outstanding for 2010 and 2009)	18,761		18,761
Capital in excess of par value	396,071		401,136
Retained earnings	5,806		61,909
Accumulated other comprehensive income	156		214
Total Common Stock Equity	420,794		482,020
Total Liabilities and Equity	$944,551		$1,109,297

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

3

The Southern Connecticut Gas Company

Statements of Cash Flows

	Successor		Predecessor
	Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Operating Activities
Net income (loss)	$5,806	$(163,467)	$14,819
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	2,112	15,645	18,055
Amortization of regulatory and other assets and liabilities, net	2,326	19,632	19,573
Deferred income taxes and investment tax credits, net	5,974	872	18,640
Pension expense	137	4,296	2,609
Goodwill impairment	-	178,885	-
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	(25,496)	14,009	42,350
Customer hardship arrearage forgiveness and      related programs	(611)	(7,395)	(20,578)
Inventories	10,862	3,420	33,688
Prepayments and other current assets	3,170	(6,233)	(3,215)
Accounts payable and accrued liabilities	11,638	(3,081)	(15,743)
Interest accrued	(850)	(937)	601
Taxes accrued	2,052	4,567	(1,969)
Other current liabilities	(753)	(936)	(686)
Other assets	(7,950)	(4,901)	(14,649)
Other liabilities	(3,226)	4,001	(876)
Net Cash Provided by Operating Activities	5,191	58,377	92,619
Investing Activities
Utility plant additions	-	(22,097)	(23,352)
Investments, net	-	6	(84)
Net Cash Used in Investing Activities	-	(22,091)	(23,436)
Financing Activities
Repurchase of common stock	-	-	-
Repayment of first mortgage bonds	-	(40,000)	-
Notes payable	2,100	4,900	(55,100)
Dividends paid on common stock	-	(14,000)	(11,000)
Net Cash Provided by (Used in) Financing Activities	2,100	(49,100)	(66,100)
Net Increase (Decrease) in Cash and Cash Equivalents	7,291	(12,814)	3,083
Cash and Cash Equivalents, Beginning of Period	4,251	17,065	13,982
Cash and Cash Equivalents, End of Period	$11,542	$4,251	$17,065

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

4

The Southern Connecticut Gas Company

Statements of Changes in Common Stock Equity

(Predecessor)

	Common Stock  Outstanding  $13.33 Par Value		Capital in  Excess of	Retained  Earnings	Accumulated  Other  Comprehensive
(Thousands, except shares)	Shares	Amount	Par Value	(Deficit)	(Loss) Income	Total
Balance, January 1, 2009	1,407,072	$18,761	$401,136	$58,090	$(487)	$477,500
Net income				14,819		14,819
Other comprehensive income, net of tax					701	701
Comprehensive income						15,520
Dividends				(11,000)		(11,000)
Balance, December 31, 2009	1,407,072	18,761	401,136	61,909	214	482,020
Net (loss)				(163,467)		(163,467)
Other comprehensive (loss), net of tax					266	266
Comprehensive (loss)						(163,201)
Dividends – common stock				(14,000)		(14,000)
Balance, November 16, 2010	1,407,072	$18,761	$401,136	$(115,558)	$480	$304,819

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

(Successor)

	Common Stock  Outstanding  $13.33 Par Value		Capital in  Excess of	Retained Earnings	Accumulated  Other  Comprehensive
(Thousands, except shares)	Shares	Amount	Par Value	(Deficit)	Income	Total
Balance, November 17, 2010	1,407,072	$18,761	$396,071	-	-	$414,832
Net income				5,806		5,806
Other comprehensive income, net of tax					$156	156
Comprehensive income						5,962
Balance, December 31, 2010	1,407,072	$18,761	$396,071	$5,806	$156	$420,794

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

5

Notes to Financial Statements

The Southern Connecticut Gas Company

Note 1. Significant Accounting Policies

Background: The Southern Connecticut Gas Company (SCG, the company, we, our, us) 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. The company’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 is the principal operating utility of Connecticut Energy Corporation (CEC), a wholly-owned subsidiary of UIL Holdings Corporation (UIL Holdings).  On November 17, 2010, UIL Holdings purchased CEC from Iberdrola USA, Inc. (Iberdrola USA) a wholly-owned subsidiary of Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain.  We operate under the authority of the Connecticut Department of Public Utility Control (DPUC) in Connecticut and are also subject to regulation by the Federal Energy Regulatory Commission (FERC).

We have evaluated events or transactions that occurred after December 31, 2010, for inclusion in these financial statements through March 31, 2010, which is the date these financial statements were available to be issued.

During the preparation of our 2010 financial statements, management determined that our previously issued financial statements for the year ended December 31, 2009, included errors related to the recording of certain adjustments including the overstatement of unbilled revenues and accounts receivable in the amount of approximately $1.4 million. Management has concluded that these errors did not have a material impact on the financial statements for the year ended December 31, 2009, and therefore the corrections were recorded within financial statements for the predecessor period ended November 16, 2010.

If the financial statements for 2009 were revised to reflect the errors including the identified item above and the expense of unamortized debt expense discussed in the "Early retirement of debt" section of Note 1, income before income taxes for the year ended December 31, 2009, would have been increased to approximately $14,171,000 and net income would have been increased to approximately $15,467,000.

Accounts receivable: Accounts receivable include unbilled revenues of $18 million at December 31, 2010 and 2009, and are shown net of an allowance for doubtful accounts of $2 million at December 31, 2010, and $4 million at December 31, 2009. Accounts receivable do not bear interest, although late fees may be assessed. Bad debt expense was $19 million for the predecessor period January 1, to November 16, 2010, $1.4 million for the successor period November 17, to December 31, 2010, and $23 million for 2009.

Unbilled revenues represent estimates of receivables for energy 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.

6

Notes to Financial Statements

The Southern Connecticut Gas Company

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. 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 and customer receivables, which are inherently uncertain and susceptible to change from period to period, could significantly affect the allowance for doubtful accounts estimates. During the predecessor period January 1, to November 16, 2010, we recorded an increase in the allowance for doubtful accounts of $1.3 million because we no longer consider customer security deposits when we determine the amount of our allowance for doubtful accounts.

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 $11 million at December 31, 2010 and 2009. The ARO consists primarily of obligations related to removal or retirement of: asbestos, 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.

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 a maturity date of three months or less when acquired to be cash equivalents and those investments are included in cash and cash equivalents.

	Successor	Predecessor
Supplemental Disclosure of Cash Flows Information	Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended December 31, 2009
(Thousands)
Cash paid (received) during the period:
Interest, net of amounts capitalized	$2,497	$16,155	$16,819
Income taxes, net of cash paid	-	$(2,036)	$(19,590)

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Notes to Financial Statements

The Southern Connecticut Gas Company

We have decreased utility plan additions by $1.6 million for amounts payable as of December31, 2010.

Depreciation and amortization: We determine depreciation expense 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: distribution property – 52 years, gas storage property – 38 years and other property – 31 years. Our depreciation accruals were equivalent to 2.9% of average depreciable property for 2010 and 2009.

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.

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 a potential impairment of goodwill requires a two step process. Step one of the impairment test involves comparing the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of a reporting unit exceeds its fair value, step two must be performed to determine the amount, if any, of goodwill impairment loss. If the carrying value is less than the fair value, further testing for 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.

In performing the annual impairment test, for purposes of the step one analysis, we base the determination of the fair value 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 SCG was greater than its carrying value in 2009.

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.

8

Notes to Financial Statements

The Southern Connecticut Gas Company

As a result of Iberdrola USA’s decision in May 2010 to sell SCG we updated our impairment test of goodwill in accordance with the two step process described above. We determined that the carrying value of SCG exceeded the purchase price agreed to by UIL Holdings, resulting in a goodwill impairment of $179 million. (See Note 2.)

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

Fair value measurements: The FASB has issued a number of new standards related to fair value measurements. In April 2009 the FASB issued two new standards related to fair value measurements, which we began applying effective April 1, 2009:

·   One of the new standards provides guidance for determining fair value when the volume and level of activity for an asset or liability have significantly decreased and for identifying transactions that are not orderly. It provides additional guidance to entities for estimating fair value in accordance with existing requirements when the volume and level of activity for an asset or a liability has significantly decreased. Even in those circumstances, and without considering the valuation technique(s) used, the intention of fair value measurement does not change. The new standard also provides guidance for identifying circumstances that indicate a transaction is not orderly. In addition, it amends the disclosures in connection with fair value measurements to require disclosure in interim and annual periods about the inputs and valuation techniques used to measure fair value as well as a discussion of any changes in them during the period; and to require disclosures concerning debt and equity securities according to major security types.

·   The other new standard provides amended guidance concerning the recognition and presentation of other-than-temporary impairments. It amends the guidance in U.S. generally accepted accounting principles for other-than-temporary impairment of debt securities (but not equity securities) to make it more operational and to improve the financial statement presentation and disclosure of other-than-temporary impairments on debt and equity securities.

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.

In January 2010 the FASB issued amendments to improve disclosures about fair value measurements. New disclosures that are or will be required include: 1) details of transfers in and out of Level 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.

9

Notes to Financial Statements

The Southern Connecticut Gas Company

Our adoption of the new standards related to fair value measurements had no effect on our financial position, results of operation or cash flows. Our adoption of the amendments concerning Level 3 roll forward activity effective for fiscal years beginning on or after January 1, 2011, and interim periods within those fiscal years, will not affect our results of operation, financial position or cash flows.

Other (Income) and Other Deductions:

	Successor		Predecessor
	Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Interest and dividend income	$(71)	$(232)	$(163)
Allowance for funds used during construction	(5)	(36)	-
Miscellaneous	(33)	(184)	(100)
Total other (income)	$(109)	$(452)	$(263)
Civic donations	$80	$45	$45
Early retirement of debt	-	-	1,137
Miscellaneous	167	182	376
Total other deductions	$247	$227	$1,558

Early retirement of debt:In October 2008 SCG paid premiums of $11 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 early 2009 we identified and expensed another $1 million of unamortized debt expense that should have been expensed in 2008 in connection with the early retirement of debt. Management believes that the $1 million is not material to either our 2009 or 2008 results of operation.

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.

10

Notes to Financial Statements

The Southern Connecticut Gas Company

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 plan. Amortization of total regulatory assets net of amortization of total regulatory liabilities was $18 million for the predecessor period January 1, to November 16, 2010, $2 million for the successor period November 17 to December 31, 2010, and $20 million for 2009.

Other regulatory assets and other regulatory liabilities consisted of:

	Successor	Predecessor
December 31,	2010	2009
(Thousands)
Other postretirement benefits	$14,495	$2,701
Rate surcharge	8,857	3,834
Premium on debt	30,464	-
Other	9,872	7,741
Total other regulatory assets	$63,688	$14,276
Deferred natural gas costs	-	$6,114
Revenue sharing	$7,058	8,763
Asset retirement obligations	2,761	2,687
Pension	7,618	3,984
Other	3,905	5,562
Total other regulatory liabilities	$21,342	$27,110

Related party transactions: Iberdrola USA Management Corporation provides various administrative and management services to Iberdrola USA's operating utilities, including SCG, 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 SCG by Iberdrola USA Management Corporation for the predecessor periods was approximately $8 million for January 1, to November 16, 2010, and $9 million for 2009.

UIL Holdings provides various administrative and management services to its regulated subsidiaries including SCG.  The cost of services provided to SCG by UIL Holdings was approximately $0.5 million for the period November 17, to December 31, 2010.

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

In addition, we accrue revenue pursuant to the various regulatory provisions to record regulatory assets for revenues that will be collected in the future.

Risk management: We have a purchased gas adjustment clause that allows 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 natural gas for the benefit of customers.

11

Notes to Financial Statements

The Southern Connecticut Gas Company

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 for the predecessor periods.

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 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 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 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 evaluations, as considered necessary. Actual results could differ from those estimates.

Note 2. Goodwill

Effective September 16, 2008, Iberdrola S.A purchased all the outstanding stock of Energy East Corporation. The accounting guidance for business combinations as it relates to push down accounting is addressed in SEC Staff Accounting Bulletin No. 54, Application of "Push Down" Basis of Accounting in Financial Statements of Subsidiaries Acquired by Purchase. However, in Accounting Standards Codification (ASC) 805-50-S99, the Task Force reached a consensus that push-down accounting is not required for companies that are not SEC registrants. As such, we elected to maintain the books and records on a historical cost basis and the accompanying predecessor financial statements have not been adjusted to reflect purchase accounting by Iberdrola.

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. Iberdrola USA’s decision in May 2010 to sell SCG represented a triggering event and we immediately performed an impairment test of the goodwill for SCG in accordance with the two step process described in Note 1.  We allocated $667 million of the total purchase price to SCG, including estimated working capital adjustments. We determined that the carrying value of SCG exceeded the purchase price agreed to by UIL Holdings, resulting in a goodwill impairment of $179 million.

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Notes to Financial Statements

The Southern Connecticut Gas Company

On November 17, 2010, we recorded an adjustment to goodwill, increasing it by $47 million to reflect the fair value as a result of the purchase by UIL Holdings.

The carrying amount of goodwill as of December 31, 2010 and 2009, is shown in the following table. Goodwill was not adjusted to reflect Iberdrola’s purchase of Energy East and its subsidiaries, including SCG. Goodwill was adjusted to reflect UIL Holdings’ purchase.

	Successor		Predecessor
	Period  November 17,  to December  31, 2010	Period  January 1, to  November   16, 2010	Year Ended December 31, 2009
(Thousands)
Balance at beginning of period
Goodwill	$132,474	$263,645	$263,645
Accumulated impairment losses	-	-	-
Impairment for sale of SCG	-	(178,885)	-
Balance at end of period
Goodwill	132,474	$263,645	263,645
Accumulated impairment losses	-	(178,885)	-
	$132,474	$84,760	$263,645

Note 3. Income Taxes

	Successor		Predecessor
	Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Current
Federal	$(1,739)	$6,627	$(16,184)
State	(196)	437	(4,409)
Current taxes (benefit) charge to expense	(1,935)	7,064	(20,593)
Deferred
Federal	5,683	290	16,004
State	291	611	2,702
Deferred taxes charged to expense	5,974	901	18,706
Investment tax credit amortization	-	(29)	(67)
Total	$4,039	$7,936	$(1,954)

The significant increase in current income tax expense in 2010 compared to 2009 is driven primarily by the effect of filing our 2008 federal and state income tax returns in September 2009. Those filings included a significant one-time tax deduction related to previously capitalized repair costs. The one-time deduction is a temporary difference between book and tax expense and requires normalization, resulting in an offsetting deferred tax expense and is the primary driver of the significant decrease in deferred income tax expense in 2010 as compared to 2009.

13

Notes to Financial Statements

The Southern Connecticut Gas Company

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

	Successor		Predecessor
	Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Tax expense at statutory rate	$3,446	$(54,436)	$4,503
Depreciation and amortization not normalized	38	(1,053)	(1,740)
Investment tax credit amortization	-	(29)	(67)
Removal costs	(32)	(438)	(710)
Uncollectible reserves and programs	72	1,475	(2,577)
Goodwill	-	62,610	-
Tax return and audit adjustment	-	(1,436)	(1,168)
State taxes, net of federal benefit	62	681	(1,110)
Other, net	453	562	915
	$4,039	$7,936	$(1,954)

Income taxes were $.6 million more than the federal statutory rate of 35% for the 2010 successor period. For the predecessor periods, income taxes were $62.4 million more than they would have been at the federal statutory rate for January 1, to November 16, 2010, and $6.4 million less in 2009. The successor 2010 effective tax rate was higher than the statutory rate primarily due to the effects of recurring flow-through items. The predecessor 2010 effective tax rate was higher than the statutory rate primarily due to goodwill impairment. The 2009 effective tax rate was lower than the statutory rate primarily due to recurring flow-through effects including book tax depreciation, uncollectible reserves and programs and differences in the 2008 filed tax return compared to the 2008 booked tax expense including benefits related to the early retirement of assets.

Our deferred tax assets and liabilities consisted of:

	Successor	Predecessor
December 31,	2010	2009
(Thousands)
Current Deferred Income Tax Assets	$1,919	$474
Noncurrent Deferred Income Tax Liabilities (Assets)
Depreciation	$1,896	$104,875
Unfunded future income taxes	21,725	31,975
Accumulated deferred investment tax credits	-	35
Pension	(6,730)	(5,132)
Postretirement benefits	(664)	(388)
Other	11,721	2,199
Total Noncurrent Deferred Income Tax Liabilities	27,948	133,564
Less amounts classified as regulatory liabilities
Deferred income taxes	22,282	39,854
Noncurrent Deferred Income Tax Liabilities	$5,666	$93,710
Deferred tax assets	$9,313	$5,994
Deferred tax liabilities	35,342	139,084
Net Accumulated Deferred Income Tax Liabilities	$26,029	$133,090

14

Notes to Financial Statements

The Southern Connecticut Gas Company

We have no federal tax credit or loss carryforwards and no valuation allowances.

	Successor	Predecessor
Reconciliation of Gross Income Tax Reserves	2010	2009
(Thousands)
Balance as of January 1	$4,053	-
Increases for tax positions related to prior years	-	$4,053
Decreases due to acquisition by UIL Holdings	(4,053)	-
Balance as of December 31	-	$4,053

There were no gross unrecognized tax benefits as of December 31, 2010. Gross income tax reserves decreased $4.1 million in 2010 primarily due to the elimination of the property related accumulated deferred income taxes in connection with the sale of SCG to UIL Holdings.

We have been audited through 2005 for federal income taxes. The statute of limitations in Connecticut has expired for all years through 2006. 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.

As a result of the passage of The Small Business Jobs Act in September 2010 and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 in December 2010, certain capital additions qualify for 50% bonus depreciation and 100% expensing, respectively, for tax purposes. We have elected to apply the 50% bonus and 100% expensing to the additions we have determined qualify for this accelerated tax depreciation.  There is no earnings effect related to this election as the accelerated tax depreciation creates a temporary difference that requires the establishment of a deferred tax liability.

Note 4. Long-term Debt

At December 31, 2010 and 2009, our long-term debt was (in thousands):

			Successor	Predecessor
	Interest Rates	Maturity	2010	2009
First mortgage bonds
Medium Term Note I	6.880% - 7.950%	2026 - 2028	$29,000	$29,000
Medium Term Note II	6.590%	2011	30,000	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			194,000	234,000
Unamortized premium on debt			30,464	-
			224,464	234,000
Less current portion, included in current liabilities			33,713	40,000
Total			$190,751	$194,000

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.

As of November 17, 2010, we recorded $30 million of debt premiums with an offset to a regulatory asset to reflect the fair value of the debt at the time of the purchase by UIL Holdings.

15

Notes to Financial Statements

The Southern Connecticut Gas Company

At December 31, 2010, long-term debt, including sinking fund obligations (in thousands) that will become due during the next five years is:

2011	2012	2013	2014	2015
$33,713	$2,517	$2,517	$2,517	$2,517

Note 5. Bank Loans and Other Borrowings

For the successor period, we are a joint borrower with the other operating utilities under UIL Holdings in a revolving credit agreement with a group of banks named therein that will expire on November 17, 2014 (the credit facility). Our borrowing limit under the credit facility is $150 million. The credit facility permits borrowings at fluctuating interest rates and also permits borrowings for fixed periods of time specified by each borrower at fixed interest rates determined by the Eurodollar interbank market in London (LIBOR). The credit facility also permits the issuance of letters of credit of up to $50 million.

We draw on our credit facilities to finance working capital needs, to temporarily finance certain refundings and for other corporate purposes. We had $7 million of short-term debt outstanding at December 31, 2010 and no short-term debt at December 31, 2009.

Note 6. Commitments and Contingencies

Lease obligations: SCG has lease arrangements for data processing equipment, office equipment, office space and land. Operating leases, which are charged to operating expense, consist principally of leases of office space and facilities, land, railroad rights of way and a wide variety of equipment. The future minimum lease payments under these operating leases are estimated to be as follows:

(In Thousands)

2011	$1,692
2012	1,692
2013	141
2014	-
2015	-
2016 - after	-
Total	$3,525

Note 7. Environmental

We own or have previously owned property where Manufactured Gas Plants (MGPs) operated historically. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the Resource Conservation and Recovery Act (RCRA) as well as other federal and state statutes and regulations. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized, as such, no liability was recorded as of December 31, 2010. We

16

Notes to Financial Statements

The Southern Connecticut Gas Company

have, in the past, received approval for the recovery, in our rates, of MGP-related remediation expenses and expect to seek recovery in rates for ongoing MGP-related remediation expenses for all of its MGP sites.

SCG owns property on Pine Street in Bridgeport, CT, the site of one of its former operations centers and a former MGP operation. As a result of litigation that was initiated by an abutting property owner, SCG entered into a consent order with the Connecticut Department of Environmental Protection (CDEP) for the cleanup of the site in 1998. The remediation of the site is being completed in two parts. Part A addressed ground water, free product and contamination that migrated to an abutting property and is completed. Part B addresses soil contamination at the site and is to be addressed by an approved engineered cap with a land use restriction. SCG recently received CDEP’s comments on its plan and is addressing these comments. Property located at 110 Pine Street, part of the original site, was sold in 1983. SCG may be subject to remediation expenses for this part of the site as a former owner of the property, the amount of which cannot be estimated at this time. This property is not part of the current remediation plan. Future remediation costs, for which we will seek recovery in rates, are expected to be in the range of $2 to $3 million. As of December 31, 2010, SCG has recorded a liability of $1.9 million for this site.

SCG owns property on Housatonic Avenue in Bridgeport, a former MGP site. The site is currently leased from SCG to a soil reclamation company. Remediation of waste and contaminants associated with historic use of the site as an MGP, including potential groundwater contamination and soil contamination, has not commenced. Costs associated with the remediation of the site could be significant and will be subject to a review by the DPUC as to whether these costs are recoverable in rates. SCG cannot presently estimate the costs of remediation or the likelihood of recoverability. As such, as of December 31, 2010, no liability related to this claim has been recorded.

SCG owns property located on Chapel Street in New Haven, CT, the site of one of its former operations centers and a former MGP site. The site is currently leased from SCG to Petroleum Terminals, Inc. Some portions of the original site, referred to as East Street, were sold in 1978. Limited remediation has occurred on two occasions, once in 1995 and again in 2008 to prevent contaminated ground water from migration into the adjacent waterway. These remediation activities were prompted by breaks in the underground piping causing releases that required immediate resolution. Costs associated with the most recent remediation approximated $1.2 million and were disallowed by the DPUC in the 2009 SCG rate case decision and therefore, will not be recovered in customer rates. Other parts of the original site, including a parcel located on St. John's Street were sold by SCG prior to 1978. SCG may be subject to remediation expenses for this part of the site as a former owner of the property, the amount of which cannot be estimated at this time. Costs associated with the remediation of the site could be significant and will be subject to a review by the DPUC as to whether these costs are recoverable in rates. UIL Holdings cannot presently estimate the costs of remediation or the likelihood of recoverability. As such, as of December 31, 2010, no liability related to this claim has been recorded.

17

Notes to Financial Statements

The Southern Connecticut Gas Company

Note 8. 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. Carrying amounts include related debt premiums.

	Successor		Predecessor
December 31,	2010		2009
	Carrying Amount	Estimated Fair Value	Carrying Amount	Estimated Fair Value
(Thousands)
First mortgage bonds	$224,464	$222,760	$234,000	$236,427

The carrying amounts for cash and cash equivalents, accounts receivable, notes payable and interest accrued 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.

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)
Successor 2010
Assets
Noncurrent investments   available for sale	$7,854	$7,854	-	-
Derivative	4	-	-	$4
Total	$7,858	$7,854	-	$4
Predecessor 2009
Assets
Noncurrent investments   available for sale	$6,920	$6,920	-	-
Derivative	19	-	-	$19
Total	$6,939	$6,920	-	$19

We had no significant transfers to or from Level 1 and 2 during the year ended December 31, 2010. Our policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that causes a transfer, if any.

18

Notes to Financial Statements

The Southern Connecticut Gas Company

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.

We determine the fair value of our fleet fuel derivatives using a proprietary calculation (unobservable to the market) and include the fair value measurements in Level 3. We determine the fair value of fleet fuel derivative contracts 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)
		Derivatives, Net
	Successor		Predecessor
	Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Beginning balance	$(19)	$19	$(341)
Total gains (losses) (realized/unrealized)
Included in earnings	1	(5)	247
Included in other comprehensive income	22	(33)	113
Ending balance	$4	$(19)	$19
Total losses for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period.	$4	$(19)	$19

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
(Thousands)
Total gains (losses) included in earnings for Successor period   November 17, to December 31, 2010	$1
Predecessor periods   January 1, to November 16, 2010	$(5)
Year ended December 31, 2009	$247

19

Notes to Financial Statements

The Southern Connecticut Gas Company

Note 9. Accumulated Other Comprehensive (Loss) Income

	Predecessor				Successor
	Balance January 1, 2009	2009 Change	Balance December 31, 2009	January 1 to November 16, 2010 Change	Balance November 17, 2010	November 17, to December 31, 2010 Change	Balance December 31, 2010
(Thousands)
Net unrealized holding (losses) gains   on investments, net of income tax   (expense) of $(452) for 2009,   $(185) for November 16, 2010, and   $(92) for November 17 to December   31, 2010	$(717)	$681	$(36)	$279	-	$139	$139
Amortization of pension cost for   nonqualified plans, net of income   tax benefit (expense) of $81 for   2009, $1 for November 16, 2010,   and $(0.3) for November 17 to   December 31, 2010	435	(196)	239	9	-	1	1
Unrealized gains on derivatives   qualified as hedges, net of income   tax (expense) of $(45) for 2009,   $(95) for November 16, 2010, and   $(11) for November 17 to December   31, 2010		68		143		16
Reclassification adjustment for losses   included in net income, net of income   tax (benefit) expense of $(98) for   2009, $110 for November 16, 2010,   and - for November 17 to December   31, 2010		148		(165)		-
Net unrealized (losses) gains on derivatives qualified as hedges (1)	(205)	216	11	(22)	-	16	16
Accumulated Other Comprehensive (Loss) Income	$(487)	$701	$214	$266	-	$156	$156

(1)See Risk management in Note 1.

20

Notes to Financial Statements

The Southern Connecticut Gas Company

Note 10. 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 a postretirement health care benefits plan covering substantially all of our employees. The health care plan is contributory with participants' contributions adjusted annually.

Obligations and funded status:

	Successor		Predecessor
Pension Benefits		Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Change in benefit obligation
Benefit obligation at beginning of period		$135,659	$122,537	$115,347
Service cost		159	1,482	1,508
Interest cost		565	6,424	6,929
Plan amendments		-	2,057	-
Actuarial (gain) loss		(4,673)	9,008	5,460
Special termination benefits		-	520	-
Benefits paid		(588)	(6,369)	(6,707)
Benefit obligation at end of period		$131,122	$135,659	$122,537
Change in plan assets
Fair value of plan assets at beginning of period		$83,069	$86,792	$77,875
Actual return on plan assets		7,594	1,560	15,624
Employer contributions		-	1,200	-
Adjustments		-	(114)	-
Benefits paid		(588)	(6,369)	(6,707)
Fair value of plan assets end of period		$90,075	$83,069	$86,792
Funded status at end of period		$(41,047)	$(52,590)	$(35,745)

21

Notes to Financial Statements

The Southern Connecticut Gas Company

	Successor		Predecessor
Postretirement Benefits		Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Change in benefit obligation
Benefit obligation at beginning of period		$29,259	$25,861	$24,391
Service cost		48	325	239
Interest cost		182	1,353	1,440
Plan participants’ contributions		67	468	452
Actuarial (gain) loss		(438)	3,915	1,957
Benefits paid		(312)	(2,834)	(2,684)
Transfer due to sale of SCG		43	-	-
Federal subsidy on benefits paid		-	171	66
Benefit obligation at end of period		$28,849	$29,259	$25,861
Change in plan assets
Fair value of plan assets at beginning of period		$8,474	$8,860	$7,128
Actual return on plan assets		362	1,177	1,776
Contributions		-	1,000	2,200
Benefits paid		(272)	(2,563)	(2,244)
Fair value of plan assets at end of period		$8,564	$8,474	$8,860
Funded status at end of period		$(20,285)	$(20,785)	$(17,001)

Amounts recognized in the balance sheet	Pension Benefits		Postretirement Benefits
	Successor	Predecessor	Successor	Predecessor
December 31	2010	2009	2010	2009
(Thousands)
Noncurrent liabilities	$(41,047)	$(35,745)	$(20,285)	$(17,001)

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 benefit pension and other postretirement plans. Amounts recognized as regulatory assets or regulatory liabilities consist of:

	Pension Benefits		Postretirement Benefits
	Successor	Predecessor	Successor	Predecessor
December 31,	2010	2009	2010	2009
(Thousands)
Net (gain) loss	$(11,680)	$64,604	$(717)	$9,791
Prior service cost (credit)	-	$284	-	$(124)

Our accumulated benefit obligation for defined benefit pension plans at December 31 was $126 million for 2010 and $114 million for 2009.

Our postretirement benefits were partially funded at December 31, 2010 and 2009.

22

Notes to Financial Statements

The Southern Connecticut Gas Company

The projected benefit obligation and accumulated benefit obligation exceeded the fair value of pension plan assets at December 31, 2010 and 2009. The following table shows the aggregate projected and accumulated benefit obligations and the fair value of plan assets for the underfunded pension plans.

	Successor	Predecessor
December 31	2010	2009
(Thousands)
Projected benefit obligation	$131,122	$122,537
Accumulated benefit obligation	$125,982	$113,872
Fair value of plan assets	$90,075	$86,792

Components of net periodic benefit cost and other amounts

recognized in regulatory assets and regulatory liabilities:

	Successor		Predecessor
Pension Benefits		Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Net periodic benefit cost
Service cost		$159	$1,482	$1,508
Interest cost		565	6,424	6,929
Expected return on plan assets		(587)	(7,822)	(8,955)
Amortization of prior service cost		-	117	339
Amortization of net loss		-	3,575	2,788
Special termination benefit charge		-	520	-
Net periodic benefit cost		$137	$4,296	$2,609
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities
Net loss (gain)		-	$15,384	$(1,209)
Amortization of net (loss)		$(11,680)	(3,575)	(2,788)
Current year prior service cost		-	2,057	-
Amortization of prior service cost		-	(117)	(339)
Total recognized in regulatory assets and regulatory liabilities		(11,680)	13,749	(4,336)
Total recognized in net periodic benefit cost and regulatory assets and regulatory liabilities		$(11,543)	$18,045	$(1,727)

23

Notes to Financial Statements

The Southern Connecticut Gas Company

	Successor		Predecessor
Postretirement Benefits		Period  November 17,  to December  31, 2010	Period  January 1, to  November  16, 2010	Year Ended  December  31, 2009
(Thousands)
Net periodic benefit cost
Service cost		$48	$325	$239
Interest cost		182	1,353	1,440
Expected return on plan assets		(83)	(607)	(476)
Amortization of prior service cost		-	(53)	64
Amortization of net loss		-	754	728
Net periodic benefit cost		$147	$1,772	$1,995
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities
Net (gain) loss		$(717)	$4,314	$657
Amortization of net (loss)		-	(754)	(728)
Amortization of prior service cost		-	53	(64)
Total recognized in regulatory assets and regulatory liabilities		(717)	3,613	(135)
Total recognized in net periodic benefit cost and regulatory assets and regulatory liabilities		$(570)	$5,385	$1,860

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 $2 million for 2010 and $3 million for 2009. 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.

There are no amounts of net gains, losses or prior service costs that are expected to be amortized from regulatory assets or regulatory liabilities into net periodic benefit costs for the fiscal year ending December 31, 2011.

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

Weighted-average assumptions used to determine benefit obligations at December 31,	Pension Benefits		Postretirement Benefits
	2010	2009	2010	2009
Discount rate	5.30%	5.80%	5.15%	5.80%
Rate of compensation increase	3.50%	4.00%	N/A	N/A

As of December 31, 2010, we decreased our discount rate from 5.80% to 5.30%. 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.

24

Notes to Financial Statements

The Southern Connecticut Gas Company

Weighted-average assumptions used to determine net periodic benefit cost for	Pension Benefits		Postretirement Benefit
year ended December 31,	2010	2009	2010	2009
Discount rate	5.80%	6.10%	5.80%	6.10%
Expected return on plan assets	8.75%	8.75%	8.00%	8.00%
Rate of compensation increase	4.00%	4.00%	N/A	N/A

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’ average remaining service to retirement.

Assumed health care cost trend rates to determine benefit obligations at December 31	2010	2009
Health care cost trend rate assumed for next year	7.80%	8.00%
Rate to which cost trend rate is assumed to decline (the ultimate rate trend rate)	4.50%	4.50%
Year that the rate reaches the ultimate trend rate	2028	2028

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	$13	$(11)
Effect on postretirement benefit obligation	$1,421	$(1,214)

Plan assets:The SCG pension plan assets were transferred as part of the acquisition on November 16, 2010. UIL Holdings is responsible for the oversight and management of these assets and has engaged BNY Mellon as the trustee and investment manager to assist in areas of asset allocation and rebalancing, portfolio strategy implementation, and performance monitoring and evaluation. Target allocations are currently being developed for the long-term. In the interim, the assets have been invested in index funds which are approximately 50% equities and 50% fixed income instruments. The governance process is similar to that of the UIL Holdings pension plan assets, including oversight by the Retirement Benefits Plans Investment Committee of the Board of Directors in conjunction with management.

Funding policy for the SCG Plan is being developed, but is expected to be similar to the UIL Holdings policy. Asset values as of December 31, 2010 were approximately $90 million. UIL Holdings did not make any contributions to the Gas Company Plans for the post acquisition period in 2010 and has a minimum funding requirement for 2011 currently estimated at $5 million. Depending upon final actuarial calculations, the 2011 contribution may ultimately range between $8 million and $10 million.

25

Notes to Financial Statements

The Southern Connecticut Gas Company

The SCG OPEB Plans are funded through a combination of 401(h) accounts and Voluntary Employee Benefit Association Trust (VEBA) accounts. UIL Holdings did not make any contributions to the Plan for the post acquisition period in 2010, nor does it currently plan to make a contribution in 2011.

For 2009, our pension benefits plan assets were held in Iberdrola USA’s 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 diversification 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.

26

Notes to Financial Statements

The Southern Connecticut Gas Company

The fair values of the pension benefits plan assets for SCG at December 31, 2010 and 2009, by asset category  are shown in the following table.

		Fair Value Measurements at December 31, 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)
Successor 2010
Mutual funds	$90,075	$90,075	-	-
Total	$90,075	$90,075	-	-
Predecessor 2009
Cash and cash equivalents	$1,473	$36	$1,437	-
U.S. government securities	1,911	1,911	-	-
Common stocks	38,522	38,413	109	-
Registered investment companies	4,589	4,589	-	-
Corporate bonds	14,027	-	14,027	-
Preferred stocks	266	266	-	-
Common/collective trusts	13,794	-	2,409	$11,385
Partnership/joint venture interests	3,592	-	-	3,592
Real estate investments	1,564	-	-	1,564
Other investments, principally   annuity and fixed income	7,054	800	1,204	5,050
Total	$86,792	$46,015	$19,186	$21,591

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.

27

Notes to Financial Statements

The Southern Connecticut Gas Company

·   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.

	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		$3	$11,113	$2,742	$1,507	$4,008	$19,373
Actual return on plan assets:
Relating to assets still held    at the reporting date		-	82	82	-	-	164
Relating to assets sold    during the year		-	3,606	124	(621)	-	3,109
Purchases, sales and    settlements		(3)	(3,416)	644	678	1,042	(1,055)
Transfers into and/or out of    Level 3		-	-	-	-
Balance, December 31, 2009		-	$11,385	$3,592	$1,564	$5,050	$21,591
Transfers into and/or out of    Level 3		-	(11,385)	(3,592)	(1,564)	(5,050)	(21,591)
Balance, December 31, 2010		-	-	-	-	-	-

The fair values of other postretirement benefits plan assets for SCG at December 31, 2010 and 2009, by asset category are shown in the following table.

		Fair Value Measurements at December 31, 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)
Successor 2010
Money market funds	$476	$476	-	-
Mutual funds, fixed	2,798	2,798	-	-
Mutual funds, equity	5,290	5,290	-	-
Total	$8,564	$8,564	-	-
Predecessor 2009
Money market funds	$147	$147	-	-
Mutual funds, fixed	2,683	2,683	-	-
Mutual funds, equity	4,333	4,333	-	-
Other investments	1,697	954	$395	$348
Total	$8,860	$8,117	$395	$348

28

Notes to Financial Statements

The Southern Connecticut Gas Company

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.

Diversified equity securities did not include any UIL Holdings common stock at December 31, 2010, or Iberdrola common stock at December 31, 2009.

Cash Flows

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)
2011	$7,272	$2,189	$224
2012	$7,572	$2,254	$240
2013	$7,888	$2,259	$258
2014	$8,032	$2,279	$266
2015	$8,209	$2,270	$275
2016 – 2020	$44,297	$10,393	$1,583

Note 11. Gas Distribution Rates

SCG is entitled by Connecticut statute to charge rates that are sufficient to allow them an opportunity to cover their reasonable operating and capital costs, to attract needed capital and to maintain their financial integrity, while also protecting relevant public interests.

In 2008 the DPUC, as required by Connecticut statute, initiated an investigation after SCG reported earning more than one percentage point over its authorized ROE for the previous twelve month period in each of six consecutive months. In October 2008 the DPUC issued a decision ordering an interim rate decrease for SCG of approximately $15 million, or 3.4%, effective October 24, 2008, compared to the rates previously set in the SCG 2005 rate case, and ordered SCG to file a rate case. In January 2009, SCG filed an application for a rate increase of $50.1 million, or approximately 15.2%. The DPUC’s August 2009 decision in the SCG rate proceeding ordered a 3.2% rate decrease, or approximately $12.5 million, compared to the rates set in the 2005 rate case, and reduced SCG’s authorized ROE to 9.26%. SCG appealed the DPUC order to the Connecticut superior court. Pursuant to Connecticut statute, SCG is entitled to collect through a surcharge the differential between the interim rate decrease and the rates finally set after full review. The 2009 DPUC decision ordered rates that were higher than the rates established in the interim rate decrease decision, and accordingly provided for SCG to collect a surcharge from customers. The rates established in the 2009 decision, and certain other orders, have been stayed by stipulation pending the resolution of the appeal. The stipulation stayed SCG’s collection of the surcharge and provides for the continuation of the interim rate decrease amount pending resolution of the appeal. SCG has been accruing the revenues associated with the surcharge for purposes of calculating its earnings. SCG has not appealed the 2009 case’s elimination of SCG’s weather normalization provision; however, this

29

Notes to Financial Statements

The Southern Connecticut Gas Company

provision has remained in effect pending resolution of the appeal. In April 2010 the Connecticut superior court ruled against SCG’s appeal. SCG appealed from the superior court’s dismissal, and that appeal is now pending at the Connecticut supreme court. The stay remains in effect.

On December 28, 2010, the DPUC denied a petition from the Office of Consumer Counsel, finding that SCG had not earned more than one percentage point over its authorized ROE for the previous twelve month period in each of six consecutive months, but opened a docket to determine whether SCG is charging rates that may be more than just, reasonable and adequate and whether its rates need to be decreased on an interim basis. The DPUC proceeding is currently pending.

SCG has purchased gas adjustment clauses, approved by the DPUC which enable them to pass the reasonably incurred cost of natural gas purchases through to customers. The clauses allow us to recover changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk.

SCG satisfies its natural gas supply requirements through purchases from various producer/suppliers, withdrawals from natural gas storage capacity contracts and winter peaking supplies and resources. We operate diverse portfolios of natural gas supply, firm transportation, gas storage and peaking resources. We contract for such natural gas resources in our own name for regulatory and other reasons. Our actual incurred natural gas cost is passed through to customers through state regulated purchased gas adjustments mechanisms subject to regulatory review.

The majority of our natural gas supply purchased is acquired at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. We diversify our sources of supply by amount purchased and location and collectively at any time acquire supplies from 10 or more producers of natural gas. We primarily acquire natural gas at various locations in the US Gulf of Mexico region, in the Appalachia region, in Canada and various other locations.

We acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system. Tennessee Gas Pipeline, Algonquin Gas Transmission and Iroquois Gas Transmission interconnect with our distribution system and the other pipelines provide indirect services upstream of the city gates.

The prices and terms and conditions of the firm transportation capacity long-term contracts are regulated by the FERC. Similar to the treatment of gas costs, the actual cost of such contracts is passed through to customers through state regulated purchased gas adjustment mechanisms which are subject to regulatory review. On November 30, 2010, the Tennessee Gas Pipeline Company (Tennessee) filed a FERC rate case proposing significant rate increases across their entire system which runs from south Texas through New England. On December 29, 2010, the FERC issued an order setting the Tennessee rate proceeding for hearing and suspended the proposed rate increase until June 1, 2011, at which time Tennessee has the right to place the rates into effect, subject to refund. The proposed increase would nearly double the fixed cost of reserving pipeline capacity but provide lower variable costs, resulting in a significant net cost increase. We will continue to oppose Tennessee’s proposal and address issues raised by actively participating in the Tennessee FERC proceedings in conjunction with other gas companies and interveners in the Northeastern United States.

30

Notes to Financial Statements

The Southern Connecticut Gas Company

We acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer for subsequent withdrawal in the winter. The storage facilities are located in Pennsylvania, New York, West Virginia and Michigan.

Winter peaking resources are attached to the local distribution system through which we have rights to the natural gas stored in a liquefied natural gas facility.

On March 25, 2011, SCG, together with the Office of Consumer Counsel, filed a motion with the DPUC to reopen SCG rate cases for the purposes of reviewing and approving a settlement agreement. The motion also requests that the procedural schedule in SCG’s potential overearnings docket be suspended until the DPUC issues a decision on the settlement. If approved, the settlement agreement would, among other things, resolve all pending issues with respect to the DPUC’s decisions in SCG’s rate cases, and would also result in the termination of the DPUC’s pending investigation of potential SCG overearnings, upon a finding that SCG’s rates are not more than just, reasonable and adequate.

Note 12. Acquisition

On November 16, 2010, UIL Holdings completed its acquisition (the Acquisition) from Iberdrola USA of SCG.  UIL Holdings accounted for the Acquisition in accordance with ASC 805 “Business Combinations”, whereby the purchase price paid was allocated to tangible assets acquired and liabilities assumed as well as goodwill based upon their fair values as of the closing date.  UIL Holdings has determined that the historical book value of the assets and liabilities of SCG approximates their fair value given the regulation they operate under in Connecticut.  Additional adjustments to the values of assets and liabilities recognized in the Acquisition may occur as the allocation of the consideration transferred is finalized during 2011.  Under business combination accounting guidance, UIL Holdings has up to one year from the date of the Acquisition to finalize the allocation of consideration transferred.

UIL Holdings “pushed-down” goodwill associated with the Acquisition.  In addition, pre-acquisition retained earnings and accumulated other comprehensive income (loss) balances be “charged” to capital in excess of par value at the time of acquisition.  As a result, SCG recorded $132 million of goodwill. Goodwill is calculated as the excess of the purchase price over the net assets acquired and the contributing factors to the amount recorded include expected future cash flows, potential operational synergies, the utilization of technology and cost savings opportunities in the delivery of certain shared administrative and other services.

The estimated fair values of assets acquired and liabilities assumed are based upon the information that was available as of the acquisition date, which management believes provides a reasonable basis for the estimated values.  Management is analyzing additional data necessary to finalize these fair values, which are subject to change.  While such changes could be significant, management does not expect them to be based upon the information provided to date.  The valuation, and thus the purchase price allocation, is expected to be completed as soon as practicable but no later than one year from the acquisition date.

31

Notes to Financial Statements

The Southern Connecticut Gas Company

The allocated purchase price, the fair value of identifiable assets, and the resulting goodwill are shown in the table below (in millions):

Total identifiable net assets	$289.6
Goodwill	132.5
Total purchase price, net	$422.1

As a component of the Acquisition, UIL Holdings and Iberdrola USA have agreed to effect a tax election pursuant to Section 338(h)(10) of the Internal Revenue Code (338 Election) with respect to the purchase of the stock of CEC.  The 338 Election allows UIL Holdings to treat the transaction for tax purposes as if UIL Holdings was purchasing the assets of CEC rather than the stock of each corporation.  As a result of the 338 Election, the assets of CEC have newly-established higher tax bases for tax depreciation purposes.

 32

EX-99.4

EXHIBIT 99.4

The Berkshire Gas Company

Financial Statements

Period from November 17, 2010 to December 31, 2010 (Successor),

the period January 1, 2010 to November 16, 2010 (Predecessor),

and the Year Ended December 31, 2009 (Predecessor)

The Berkshire Gas Company

Index

December 31, 2010 and 2009

	Page(s)
Reports of Independent Auditors	1
Financial Statements
Statements of Income (1)	3
Balance Sheets at December 31, 2010 (Successor) and 2009 (Predecessor)	4
Statements of Cash Flows (1)	6
Statements of Changes in Common Stock Equity (1)	7
Notes to Financial Statements	8–30

(1) For the period November 17, 2010 to December 31, 2010 (Successor), the period January 1, 2010 to November 16, 2010 (Predecessor), and the year ended December 31, 2009 (Predecessor).

1

2

The Berkshire Gas Company

Statements of Income (1)

December 31, 2010 and 2009

(in thousands)

	Successor			Predecessor
	Period			Period
	November 17, to			January 1, to			Year Ended
	December 31,			November 16,			December 31,
	2010			2010			2009
Operating revenues
Sales and services	$	12,529		$	54,633		$	64,043
Operating expenses
Natural gas purchased		5,514			27,259			30,251
Other operating expenses		1,299			10,455			12,927
Maintenance		113			878			990
Goodwill impairment		-			5,994			-
Depreciation and amortization		786			5,742			5,947
Other taxes		270			2,023			2,246
Total operating expenses		7,982			52,351			52,361
Operating income		4,547			2,282			11,682
Other income		(109	)		(1,183	)		(1,097	)
Other deductions		3			41			43
Interest charges, net		406			2,926			3,543
Income before income taxes		4,247			498			9,193
Income taxes		1,660			2,524			3,562
Net income (loss)		2,587			(2,026	)		5,631
Preferred stock dividends		1			4			6
Earnings available for common stock	$	2,586		$	(2,030	)	$	5,625

(1) For the period November 17, 2010 – December 31, 2010 (Successor), the period January 1, 2010 – November 16, 2010 (Predecessor), and the year ended December 31, 2009 (Predecessor)

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

3

The Berkshire Gas Company

Balance Sheets

December 31, 2010 (Successor) and 2009 (Predecessor)

(in thousands)

	December 31,
	2010		2009
Assets
Current assets
Cash and cash equivalents	$	5,993	$	370
Accounts receivable and unbilled revenues, net		9,989		9,216
Gas in storage at average cost		4,872		6,231
Materials and supplies at average cost		392		408
Deferred income taxes		909		600
Prepayments and other current assets		1,700		1,807
Total current assets		23,855		18,632
Utility plant, at original cost
Natural gas		156,595		152,529
Less:  Accumulated depreciation		50,211		47,453
Net utility plant in service		106,384		105,076
Construction work in progress		100		190
Total utility plant		106,484		105,266
Other property and investments, net		2,975		7,822
Regulatory and other Assets
Debt premium - UIL		8,681		-
Environmental remediation costs		14,498		13,863
Pension benefits		17,445		16,351
Other		4,058		5,203
Total regulatory assets		44,682		35,417
Other assets
Goodwill		52,476		60,660
Prepaid pension benefit		-		1,362
Long term accumulated deferred income taxes		3,127		-
Other		1,193		1,099
Total other assets		56,796		63,121
Total regulatory and other assets		101,478		98,538
Total assets	$	234,792	$	230,258

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

4

The Berkshire Gas Company

Balance Sheets

December 31, 2010 (Successor) and 2009 (Predecessor)

(in thousands)

	December 31,
	2010			2009
Liabilities
Current liabilities
Current portion of long-term debt	$	5,418		$	3,000
Notes payable		-			5,700
Accounts payable and accrued liabilities		4,356			5,211
Interest accrued		877			902
Taxes accrued		3,425			223
Environmental reserve		760			760
Derivative liability current		15			15
Other		3,930			4,635
Total current liabilities		18,781			20,446
Regulatory and other liabilities
Regulatory liabilities
Deferred income taxes		7,479			3,688
Unfunded future income taxes		163			182
Pension benefits		2,622			3,405
Accrued removal obligation		23,007			21,879
Total regulatory liabilities		33,271			29,154
Other liabilities
Deferred income taxes		17,533			18,525
Environmental remediation costs		8,070			6,520
Postretirement reserves		5,110			5,171
Other		3,061			3,103
Total other liabilities		33,774			33,319
Total regulatory and other liabilities		67,045			62,473
Long-term debt		40,263			37,000
Total liabilities		126,089			119,919
Commitments and contingencies
Preferred stock
Preferred stock		78			118
Common stock equity
Capital in excess of par value		106,046			98,199
Retained earnings		2,586			12,068
Accumulated other comprehensive loss		(7	)		(46	)
Total common stock equity		108,625			110,221
Total liabilities and stockholders' equity	$	234,792		$	230,258

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

5

The Berkshire Gas Company

Statements of Cash Flows (1)

Years Ended December 31, 2010 and 2009

(in thousands)

	Successor			Predecessor
	Period			Period
	November 17, to			January 1, to			Year Ended
	December 31,			November 16,			December 31,
	2010			2010			2009
Cash flows from operating activities
Net income (loss)	$	2,587		$	(2,026	)	$	5,631
Adjustments to reconcile net income to net cash
provided by (used in) operating activities
Depreciation		661			5,463			5,976
Amortization of regulatory assets and liabilities		125			279			(29	)
Deferred income taxes and investment tax credits, net		347			(1,040	)		5,122
Pension income (expense)		30			413			(219	)
Changes in current operating assets and liabilities
Accounts and other receivables		(5,322	)		4,549			827
Inventories		1,090			285			4,316
Prepayments and other current assets		(97	)		(519	)		(948	)
Accounts payable and accrued liabilities		578			(1,433	)		(1,135	)
Taxes accrued		1,536			1,666			(123	)
Interest accrued		387			(412	)		(39	)
Other current liabilities		(1,025	)		321			(3,483	)
Other assets		(7,300	)		6,755			(2,841	)
Other liabilities		261			1,311			1,794
Net cash (used in) provided by operating activities		(6,142	)		15,612			14,849
Cash flows from investing activities
Utility plant additions		(842	)		(5,388	)		(4,268	)
Contributions in aid of construction		(42	)		309			306
Other property and investments, net		(27	)		4,625			(367	)
Net cash used in investing activities		(911	)		(454	)		(4,329	)
Cash flows from financing activities
Long term note repayments		(2,418	)		(3,000	)		(3,000	)
Long term debt issuances		8,681			-			-
Notes payable issuances		-			2,000			-
Notes payable repayments		-			(7,700	)		(3,300	)
Redemption of preferred stock		-			(40	)		(4	)
Dividends on preferred stock		(1	)		(4	)		(6	)
Dividends on common stock		-			-			(5,613	)
Net cash provided by (used in) financing activities		6,262			(8,744	)		(11,923	)
Net (decrease) increase in cash and cash equivalents		(791	)		6,414			(1,403	)
Cash and cash equivalents
Beginning of period		6,784			370			1,773
End of period	$	5,993		$	6,784		$	370

(1) For the period November 17, 2010 – December 31, 2010 (Successor), the period January 1, 2010 – November 16, 2010 (Predecessor), and the year ended December 31, 2009 (Predecessor)

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

6

The Berkshire Gas Company

Statements of Changes in Common Stock Equity (1)

Years Ended December 31, 2010 and 2009

(in thousands, except number of shares and par value amounts)

	Common Stock									Accumulated
	Outstanding				Capital in					Other			Total
	$2.50 Par Value				Excess of		Retained			Comprehensive			Common
	Share		Amount		Par Value		Earnings			Income (Loss)			Equity
Balance at January 1, 2009 (Predecessor)		100	$	250	$	98,199	$	12,056		$	(228	)	$	110,027
Net income								5,631						5,631
Other comprehensive income, net of tax											182			182
Comprehensive income														5,813
Dividends on common equity								(5,613	)					(5,613	)
Dividends on preferred stock								(6	)					(6	)
Balance at January 1, 2010 (Predecessor)		100		250		98,199		12,068			(46	)		110,221
Net loss								(2,026	)					(2,026	)
Other comprehensive income, net of tax											43			43
Comprehensive loss														(1,983	)
Dividends on preferred stock								(4	)					(4	)
Balance at November 16, 2010 (Predecessor)		100	$	250	$	98,199	$	10,038		$	(3	)	$	108,234
Balance at November 17, 2010 (Successor)		100	$	250	$	106,046	$	-		$	-		$	106,046
Net income								2,587						2,587
Other comprehensive loss, net of tax											(7	)		(7	)
Comprehensive income														2,580
Dividends on preferred stock								(1	)					(1	)
Balance at December 31, 2010 (Successor)		100	$	250	$	106,046	$	2,586		$	(7	)	$	108,625

(1) For the period November 17, 2010 – December 31, 2010 (Successor), the period January 1, 2010 – November 16, 2010 (Predecessor), and the year ended December 31, 2009 (Predecessor)

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

7

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

1.   Significant Accounting Policies

Background

The Berkshire Gas Company (Berkshire, the Company, we, our, us) is a subsidiary of Berkshire Energy Resources, a Massachusetts Business Trust, which is a wholly-owned subsidiary of UIL Holdings Corporation.  The Company is engaged in the distribution and sale of natural gas for residential, commercial and industrial use, as well as the transportation of natural gas for larger commercial and industrial users.  The Company also sells and leases gas-burning equipment.  The Berkshire Gas Company is subject to regulation by the Massachusetts Department of Public Utilities (DPU) as it relates to utility service.  Berkshire is currently operating under a 10-year rate plan approved by the DPU which expires on January 31, 2012, pursuant to which Berkshire’s rates can be adjusted annually.  The ROE approved in Berkshire’s rate plan is 10.50%.  The Company’s accounting policies conform to Generally Accepted Accounting Principles (GAAP) as applied to public utilities giving effect to the accounting practices and policies of the DPU.

We have evaluated events or transactions that occurred after December 31, 2010, for inclusion in these financial statements through March 31, 2011, which is the date these financial statements were available to be issued.

Effective November 17, 2010, Berkshire Gas Company became a wholly-owned subsidiary of UIL Holdings Corporation., a U.S. corporation.  The acquisition was a business combination whereby certain subsidiaries of Iberdrola, S.A. including Berkshire Gas Company, became wholly-owned subsidiaries of UIL Holdings Corporation.  The acquisition was completed through the purchase of all of the outstanding common stock of Berkshire Gas Company.  The effects of the acquisition required for accounting purposes, including any allocation of goodwill, were pushed down to Berkshire Gas.  The accompanying financial statements have been adjusted to reflect UIL’s basis in Berkshire Gas.

Basis of Presentation

Due to the acquisition of Berkshire Gas by UIL Holdings Corporation, the Company’s Financial Statements are presented for the following periods:  (i) the successor period November 17, 2010 – December 31, 2010; (ii) the predecessor period January 1, 2010 – November 16, 2010; and (iii) the predecessor period twelve months ended December 31, 2009.  The Balance sheet is presented at December 31, 2010 as the successor company and December 31, 2009 as the predecessor company.

Accounts Receivable

Accounts receivable on the balance sheet are shown net of an allowance for doubtful accounts of $1,260 at December 31, 2010, and $1,150 at December 31, 2009.  Accounts receivable includes unbilled revenues of $1,891 at December 31, 2010, and $1,496 at December 31, 2009.  Accounts receivable do not bear interest although late fees may be assessed.  Bad Debt expense was $417 in 2010 and $288 in 2009.

Unbilled revenues represent estimates of receivables for energy 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.

8

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our existing accounts receivable, determined based on experience and other economic data.  Each month we review the 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 accounts estimates.

Inventory

The Company acquires firm underground natural gas storage capacity using long-term contracts and fill storage facilities with gas in the summer for subsequent withdrawal in the winter.  The Company holds two gas storage contracts with two different storage contractors.  The storage facilities are located in Pennsylvania, New York and West Virginia.

Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted by The Company, which is a Local Distribution Company (LDC).  The Company owns or has rights to the natural gas stored in a Liquefied Natural Gas (LNG) facility directly attached to its distribution system.

Accrued Removal Obligations

We meet the requirements concerning the accounting for 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 costs.

As of December 31, 2010 and 2009 accrued removal obligations totaled approximately $23 million and $21.9 million, respectively.  The removal obligation primarily relates to the Company’s mains and services and is reserved through the approved depreciation rates.  Berkshire does not have a legal obligation related to the cost of removal reserve.

Depreciation and Amortization

The Company determines 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, as approved by the DPU.  The Company’s depreciation accruals were equivalent to 3.47% of average depreciable property for 2010 and 2009.

The Company charges repairs and minor replacements to operating expense accounts, and capitalizes renewals and betterments, including certain indirect costs.  The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage value are charged to accumulated depreciation.

Goodwill

We are required to perform an annual goodwill impairment test at the same time each year and, accordingly, we perform our annual impairment testing of goodwill 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 than fair value, further testing of goodwill impairment is not performed.

9

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

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.

In performing the annual impairment test, for purposes of the step one analysis, we base the determination of the fair value on the income approach, which estimates fair value based on discounted future cash flows.  Based on the decision in May 2010 by Iberdrola to sell Berkshire Gas Company, a triggering event was recognized and the goodwill was immediately tested for impairment according to the two step process outlined above.  It was determined that the fair value of Berkshire Gas Company’s goodwill was less than its carrying value, resulting in a goodwill impairment totaling $5,994.  At November 17, 2010 as part of the acquisition allocation, Berkshire Gas Company recorded an adjustment to goodwill to reduce it by $2,190 to reflect the fair value of the purchase by UIL. (Note 3)

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.

New Accounting Standards Adopted

We have adopted new accounting standards issued by the FASB as explained below.

Disclosures About Fair Value Measurements

The FASB has issued a number of new standards related to fair value measurements.

In January 2010, the FASB issued updated guidance to ASC 830 “Fair Value Measurements and Disclosures” which requires disclosure of transfers in and out of assets and liabilities that fall within Level 1 and 2 of the fair value hierarchy as described in Note 10 – Fair Value of Financial Instruments as well as the gross presentation of activities within the reconciliation of changes in the fair value of Level 3 assets and liabilities.  This guidance is effective in the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 reconciliation information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years.  These requirements impact footnote disclosures only and will not affect our results of operation, financial position or cash flows.

10

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

In April 2009 the FASB issued two new standards related to fair value measurements, which we began applying effective April 1, 2009:

·   One of the new standards provides guidance for determining fair value when the volume and level of activity for an asset or liability have significantly decreased and for identifying transactions that are not orderly.  It provides additional guidance to entities for estimating fair value in accordance with existing requirements when the volume and level of activity for an asset or a liability has significantly decreased.  Even in those circumstances, and without considering the valuation technique(s) used, the intention of fair value measurement does not change.  The new standard also provides guidance for identifying circumstances that indicate a transaction is not orderly.  In addition, it amends the disclosures in connection with fair value measurements to require disclosure in interim and annual periods about the inputs and valuation techniques used to measure fair value as well as a discussion of any changes in them during the period; and to require disclosures concerning debt and equity securities according to major security types.  The new standard is effective for interim and annual reporting periods ending after June 15, 2009, and must be applied prospectively.  Our adoption of the new requirements effective for our financial statements issued for fiscal years and interim periods beginning on or after April 1, 2009, did not affect our financial position, results of operation or cash flows.

·   The other new standard provides amended guidance concerning the recognition and presentation of other-than-temporary impairments.  It amends the guidance in U.S. generally accepted accounting principles (GAAP) for other-than-temporary impairment of debt securities (but not equity securities) to make it more operational and to improve the financial statement presentation and disclosure of other-than-temporary impairments on debt and equity securities.  The amended guidance is effective for interim and annual reporting periods ending after June 15, 2009.

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.

In January 2010 the FASB issued amendments to improve disclosures about fair value measurements.  New disclosures that are or will be required include: 1) details of transfers in and out of Level 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.

11

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

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.  Our adoption of the amendments concerning Level 3 roll forward activity effective for fiscal years beginning on or after January 1, 2011, and interim periods within those fiscal years, will not affect our results of operation, financial position or cash flows.

Other (Income)

Other (Income) is composed of interest income on deferred gas costs which is recovered in rates and rental revenues from water heater rentals.

Purchased Gas Adjustment Clause

Berkshire Gas has a cost of gas adjustment clause, approved by the DPU, which enables the Company to pass the reasonably incurred cost of gas purchases through to customers.  This clause allows the Company to recover changes in the market price of purchased natural gas, substantially eliminating the exposure to natural gas price risk.

Regulatory Assets and Liabilities

Berkshire Gas currently meets the requirements concerning the accounting for regulated operations for their regulated natural gas operations in Massachusetts; however, we cannot predict what effect the competitive market or future actions of regulatory entities would have on their ability to continue to do so.  If our company were to no longer meet the requirements concerning accounting for regulated operations for all or a separable part of their 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 the Company capitalizes, 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.  It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.

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.  Amortization of total regulatory assets net of amortization of total regulatory liabilities was $404 in 2010.  Amortization of total regulatory liabilities net of amortization of total regulatory assets was $29 in 2009.

Other regulatory assets as of December consisted of:

	2010		2009
Deferred gas costs	$	3,320	$	4,352
Recoverable bad debts		570		579
Deferred rate case costs		118		227
Deferred other		50		45
Total other regulatory assets	$	4,058	$	5,203

12

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

Related Party Transactions

UIL Holdings provides various administrative and management services to UIL Holdings’ regulated subsidiaries including Berkshire Gas Company, Connecticut Natural Gas Corporation and Southern Connecticut Gas Company.  The cost of services provided to Berkshire Gas Company by UIL Holdings was approximately $122 for the period November 17, 2010 to December 31, 2010.  The cost for services provided to Berkshire Gas by Connecticut Natural Gas Corporation and Southern Connecticut Gas Company during 2010 was $181.  The inter-company receivable balance due from Connecticut Natural Gas Corporation, Southern Connecticut Gas Company was $325 as of December 31, 2010.  Amounts payable to Connecticut Natural Gas Corporation, Southern Connecticut Gas Company and UIL Holdings Corporation as of December 31, 2010 was $339.

Iberdrola USA Management Corporation and its regulated subsidiaries including Connecticut Natural Gas Corporation, Southern Connecticut Gas Company, Central Maine Power, New York State Electric and Gas Corporation provided various administrative and management services to Berkshire Gas, pursuant to service agreements in place through November 16, 2010.  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.  The cost for services provided to Berkshire Gas by Iberdrola USA Management Corporation, Central Maine Power and New York State Electric and Gas Corporation for the period January 1, 2010 through November 16, 2010 was $2,868.

During 2009, the cost of services provided to Berkshire Gas by Iberdrola USA Management, Connecticut Natural Gas Corporation, Southern Connecticut Gas Company, Central Maine Power and New York State Electric and Gas Corporation was $3,837.  The inter-company balances owed to Berkshire Gas from Iberdrola USA Management, Connecticut Natural Gas Corporation, Southern Connecticut Gas Company, Central Maine Power and New York State Electric and Gas Corporation was $1,610 as of December 31, 2009.  Amounts payable to Iberdrola USA Management, Connecticut Natural Gas Corporation, Southern Connecticut Gas Company, Central Maine Power, New York State Electric and Gas Corporation was $178 as of November 16, 2010, $486 as of December 31, 2009.

Revenue Recognition

The Company recognizes revenues upon delivery of energy and energy related products and services to its customers.

Pursuant to the DPU, the Company recovers the cost of gas supplies through the seasonal Cost of Gas Adjustment Clause (CGAC), and recovers the cost of other distribution charges through the Local Distribution Adjustment Clause (LDAC).

Berkshire is currently under a 10-year price cap incentive based rate plan approved by the DPU.  This plan, which went into effect in February 2002, allows annually, after a 31-month rate freeze, for an increase in rates of the rate of inflation less a 1% productivity offset.  After five years, the plan would require a mid-period review by the DPU.  In August, 2008, Berkshire received an order from the DPU pursuant to its mid-period review.  Specifically, the DPU found that the Company’s rates under its 10-year price cap incentive based rate plan are just and reasonable and that the plan should continue, without modifications, with successive annual adjustments through 2012.  In September 2010 the DPU allowed for a rate decrease of approximately 0.21%, effective September 1, based on the predetermined formula.  In September 2009 the DPU allowed for a rate increase of approximately 1.2%, effective September 1, based on the predetermined formula.

13

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

Risk Management

The Company has purchased gas adjustment clauses that allow it to recover through rates any changes in the market price of purchased natural gas, substantially eliminating its exposure to natural gas price risk.

To provide financial protection from dramatic weather fluctuations, the Company purchased a weather insurance contract for the calendar year 2010, the winter period from January 1, 2010 through April 30, 2010, and from November 1, 2010 through December 31, 2010.  The cost of the 2010 weather contract is approximately $159 and was recorded as a prepaid asset and amortized over the coverage period.  The amount expensed through November 16, 2010 was $120 with the balance of $39 expensed November 17, 2010 through December 31, 2010.  Berkshire also purchased weather insurance for the same periods in 2009.

The comparative cost for 2009 was $160 and the cost was recorded as a prepaid asset and amortized over the coverage period.  The Company recognized insurance proceeds totaling $123 as of November 16, 2010.  No proceeds were recognized for the period November 17, 2010 through December 31, 2010.  The Company did not recognize insurance proceeds in 2009.  The Company does not hold or issue financial instruments for trading or speculative purposes.

Statements of Cash Flows

The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents.

	2010		2009
Supplemental disclosure of cash flows information
Cash paid during the year ended December 31	$	-	$	-
Interest, net of amounts capitalized		3,263		3,494
Income taxes, net of benefits received		1,663		(1,389	)

Interest capitalized was $4 in 2010 and $2 in 2009.

Taxes

Berkshire computes its income tax provision on a separate return method.  The determination and allocation of Berkshire's income tax provision and its components are outlined and agreed to in its tax sharing agreement with Iberdrola USA through November 16, 2010.

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.

Unamortized Debt Expense

The issuance costs associated with long-term debt are deferred and amortized over the life of the issue.

14

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

Use of Estimates and Assumptions

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting period.  Significant estimates and assumptions are used for, but not limited to: (1) allowance for doubtful accounts; (2) asset impairments, including goodwill; (3) depreciable lives of assets; (4) income tax valuation allowances; (5) uncertain tax positions; (6) reserves for professional, workers compensations, 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 estimates used in the preparation of our 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.

2.   Acquisition

In May of 2008, Iberdrola S.A. purchased all the outstanding stock of Energy East Corporation, of which Berkshire Gas Company was a wholly owned subsidiary.  The accounting guidance for business combinations as it relates to push down accounting is addressed in SEC Staff Accounting Bulletin No. 54, Application of “Push Down” Basis of Accounting in Financial Statements of Subsidiaries Acquired by Purchase.  However, in ASC 805-50-S99, the Task Force reached a consensus that push-down accounting is not required for companies that are not SEC registrants.  As such, the Company elected to maintain the books and records on a historical cost basis and the accompanying predecessor financial statements have not been adjusted to reflect purchase accounting by Iberdrola.

On November 16, 2010, UIL Holdings completed its acquisition (the Acquisition) from Iberdrola USA of Berkshire Gas Company.  UIL Holdings accounted for the Acquisition in accordance with ASC 805 “Business Combinations”, whereby the purchase price paid was preliminarily allocated to tangible and intangible assets acquired and liabilities assumed as well as goodwill based upon their fair values as of the closing date.  UIL Holdings has determined that the historical book value of the assets and liabilities of Berkshire Gas Company approximates their fair value given the regulation they operate under in Massachusetts.  Additional adjustments to the values of assets and liabilities recognized in the Acquisition may occur as the allocation of the consideration transferred is finalized during 2011.  Under business combination accounting guidance, UIL Holdings has up to one year from the date of the Acquisition to finalize the allocation of consideration transferred.  The following table summarizes the allocation of the purchase price:

(in millions)
Total identifiable net assets	$	54.3
Goodwill		52.5
Total purchase price, net	$	106.8

15

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

UIL “pushed-down” goodwill associated with the Acquisition.  In addition, pre-acquisition retained earnings and accumulated other comprehensive income (loss) balances were “charged” to capital in excess of par value at the time of acquisition.  As a result, Berkshire Gas Company recorded $52,476 of goodwill.  Goodwill is calculated as the excess of the purchase price over the net assets acquired and the contributing factors to the amount recorded include expected future cash flows, potential operational synergies, the utilization of technology and cost savings opportunities in the delivery of certain shared administrative and other services.

The estimated fair values of assets acquired and liabilities assumed are based upon the information that was available as of the acquisition date, which management believes provides a reasonable basis for the estimated values.  Management is analyzing additional data necessary to finalize these fair values, which are subject to change.  While such changes could be significant, management does not expect them to be based upon the information provided to date.  The valuation, and thus the purchase price allocation, is expected to be completed as soon as practicable but no later than one year from the acquisition date.

3.   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.  In May 2010, as a result of the decision by Iberdrola to sell the Company to UIL Holdings Corporation, an impairment test was performed in accordance with the two step process described in Note 1.  Iberdrola allocated $146 million of the total purchase price, including estimated working capital adjustments to Berkshire Gas Company.  It was determined that the carrying value of the Company exceeded the purchase price agreed to by UIL, resulting in a goodwill impairment of $5,994.

At November 17, 2010 as part of the acquisition allocation, Berkshire Gas Company recorded an adjustment to goodwill to reduce it by $2,190 to reflect the fair value of the purchase by UIL.

We had no impairment of goodwill in 2009 and no impairment was indicated within any of the ranges of assumptions analyzed.  Our discounted cash flow analysis included some points at the low end of the range where the fair value approximated the carrying value.  As a result, management performed more detailed analysis, including scenario analysis.  Management determined that the fair value of Berkshire’s goodwill as of December 31, 2009 was greater than its carrying value.

16

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

The carrying amount of goodwill as of December 31, 2010 and 2009, is shown in the following table.  Goodwill was adjusted to reflect UIL’s purchase.

	Successor		Predecessor
	November 17, to		January 1, to			Year Ended
	December 31,		November 16,			December 31,
	2010		2010			2009
Balance at beginning of period
Goodwill	$	52,476	$	60,660		$	60,660
Impairment for natural gas companies sold				(5,994	)
Balance at end of period		52,476		54,666			60,660
Goodwill				60,660			60,660
Accumulated impairment losses				(5,994	)		-
	$	52,476	$	54,666		$	60,660

4.   Income Taxes

	Successor			Predecessor
	November 17,			January 1, to
	Through			Through			Year Ended
	December 31,			November 16,			December 31,
	2010			2010			2009
Current
Federal	$	1,101		$	3,032		$	(1,361	)
State		213			531			(199	)
Current taxes charged to expense		1,314			3,563			(1,560	)
Deferred
Federal		289			(889	)		4,373
State		63			(108	)		797
Deferred taxes charged to expense		352			(997	)		5,170
Investment tax credit (ITC) adjustments		(6	)		(42	)		(48	)
Total income tax	$	1,660		$	2,524		$	3,562

The significant increase in current income tax expense in 2010 as compared to 2009 is driven primarily by the effect of environmental costs and bonus depreciation.

17

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

The company’s tax expense differed from the expense at the statutory rate of 35% due to the following:

	Successor			Predecessor
	November 17,			January 1, to
	Through			Through			Year Ended
	December 31,			November 16,			December 31,
	2010			2010			2009
Tax expense at statutory rate	$	1,486		$	174		$	3,217
Effect of goodwill impairment adjustment		-			2,098			-
State taxes, net of federal benefit		180			275			389
ITC amortization		(6	)		(42	)		(48	)
Other		-			19			4
Total income tax	$	1,660		$	2,524		$	3,562

The effective tax rate was 39% in 2010 and 2009.  The adjustment for goodwill impairment recorded as a result of the sale is not recognized as a taxable expense.

18

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

At December 31, 2010 and 2009, the deferred tax assets and liabilities consisted of:

	Successor			Predecessor
	2010			2009
Current deferred income tax assets
Other	$	909		$	600
Total current deferred income tax assets		909			600
Noncurrent deferred income tax assets
Other		3,127			-
Total noncurrent deferred income tax assets		3,127			-
Total deferred income tax assets		4,036			600
Noncurrent deferred income tax liabilities
Property related		12,909			13,272
Pension		5,357			5,202
Early retirement reserves		(1,831	)		(2,003	)
Accumulated deferred ITC		416			464
Refundable gas costs		1,341			1,746
Environmental		2,180			2,668
Regulatory and other		4,640			864
Total noncurrent deferred income tax liabilities		25,012			22,213
Less:  Amounts classified as regulatory liabilities		-			-
Deferred income taxes		7,479			3,688
Noncurrent deferred income tax liabilities		17,533			18,525
Deferred tax assets		5,867			2,603
Deferred tax liabilities		26,842			24,216
Net accumulated deferred income tax liabilities	$	20,975		$	21,613

	Successor			Predecessor
Reconciliation of gross income tax reserves	2010			2009
Balance at beginning of period	$	168		$	-
Increases (decreases) for tax provisions related
to prior years		(5	)		168
Balance at end of period	$	163		$	168

19

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

The total gross unrecognized tax benefits as of December 31, 2010 was $163 thousand including gross income tax reserves of $159 thousand and interest of $4 thousand.  The total gross unrecognized tax benefits as of December 31, 2009 were $172 thousand including income tax reserves of $168 thousand and interest of $4 thousand.  Gross income tax reserves decreased $5 thousand in 2010, primarily due to the net effect of the state reserve on the federal reserve.  Gross income tax reserves increased $168 thousand in 2009, primarily due to accelerated deductions taken on the 2008 federal and state returns.

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

5.   Long-Term Debt

Details regarding the Company's long-term debt as of December 31 are as follows:

	Interest Rates			Maturity		2010		2009
Description
First Mortgage Bond Series P		10.06	%		2019	$	10,000	$	10,000
Senior Unsecured Note		9.60	%		2020		8,000		8,000
Senior Unsecured Note		7.80	%		2021		16,000		16,000
Commercial Note		4.76	%		2011		3,000		6,000
Unamortized Debt Premium							8,681		-
							45,681		40,000
Less:  Current portion liabilities							5,418		3,000
						$	40,263	$	37,000

The aggregate amounts of maturities due are $5,418 in 2011 and $1,455 in 2012 through 2014.  The First Mortgage Bond is collateralized by substantially all of the utility plant.  The Indentures of the Series P Mortgage Bond and 7.8% Senior Unsecured Note contain certain restrictive and financial covenants, principally a fixed charge ratio, and limitation on funded debt.

As of December 31, 2010, the Company was in compliance with the debt covenants established in connection with the issue of the bonds and notes.

6.   Bank Loans and Other Borrowings

On November 17, 2010, UIL Holdings, and its regulated subsidiaries including Berkshire Gas Company entered into a revolving credit agreement with a group of banks named therein that will expire on November 17, 2014 (the credit facility).  The borrowing limit under the credit facility is $400 million of which $50 million is available to Berkshire.  The credit facility permits borrowings at fluctuating interest rates and also permits borrowings for fixed periods of time specified by each Borrower at fixed interest rates determined by the Eurodollar interbank market in London (LIBOR).  The credit facility also permits the issuance of letters of credit of up to $50 million.

20

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

As of December 31, 2010, Berkshire had $ -0- outstanding under the Credit Facility.  Borrowings under this facility are classified as short-term debt, but the agreement has longer term commitments from banks allowing the Company to borrow and reborrow funds, at its option, to November 17, 2014, thus affording it flexibility in managing its working capital requirements.

Through Iberdrola USA, the Company had a line of credit of $15 million and an uncommitted bilateral credit agreement for a total of $5 million.  A total of $14.3 million was available as of December 31, 2009.  Berkshire, along with other Iberdrola USA operating companies, was a joint borrower in a revolving credit facility providing maximum borrowings of up to $475 million in aggregate of which Berkshire’s allotted line was $15 million through November 16, 2010 and for all of 2009.  Sublimits that total to the aggregate limit applied to each joint borrower and could be altered within the constraints imposed by maximum limits that applied to each joint borrower.  The credit facility had an expiration date in 2012 and required fees on undrawn borrowing capacity.  In connection with this line of credit, the Company borrowed at less than the prime rate.  The uncommitted bilateral credit agreement expired in May 2010.  In lieu of compensating balance requirements, the Company paid facility fees of 8 basis points on the line of credit and 15 basis points on the bilateral credit agreement.

In the Iberdrola revolving credit facility, Berkshire 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.  For purposes of calculating the maximum ratio of consolidated indebtedness to total capitalization, the facility excludes from consolidated net worth the balance of Accumulated other comprehensive income (loss) as it appears on the consolidated balance sheet.  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 for the party in default.  At December 31, 2009, our ratio of total indebtedness to total capitalization pursuant to the revolving credit facility was 0.29 to 1.00.  We were not in default as of November 16, 2010 and December 31, 2009.

Information as to short-term borrowings for the year ended December 31, is as follows:

	2010			2009
Bank balance outstanding at December 31	$	-		$	5,700
Average interest rate at end of year		0.24	%		0.57	%
Weighted average interest rate during the year		0.55	%		0.65	%

7.   Redeemable Cumulative Preferred Stock

The Company has one series of 4.8% cumulative preferred stock authorized.  The redemption price per share (as well as the amount due on voluntary liquidation) is $100.00.  The provisions of the 4.8% cumulative preferred stock require the Company to offer to purchase up to 450 shares at par annually on September 15th.  Pursuant thereto, the Company purchased 406 shares during calendar year 2010 and 36 shares during calendar year 2009.  As of December 31, 2010, Berkshire did not have any authorized but unissued preferred stock.

21

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

At December 31, 2010 and 2009, the preferred stock was:

(in thousands except per share amounts)
		Redemption
	Par Value	Price
Series	Per Share	Per Share	Shares Authorized and Outstanding		Amount
			2010	2009	2010	2009
Berkshire Gas, 4.80%	$           100	$           100	$              776	$           1,182	$           78	$         118

8.   Commitments and Contingencies

Capital Spending

The Company has no material commitments in connection with its capital spending program.  We plan to invest $9,600 in our energy delivery infrastructure in 2011.  Capital spending is expected to be paid for with both short-term debt and internally-generated funds.  The program is subject to periodic review and revision.  The Company’s capital spending will be primarily for the extension of energy delivery service and necessary improvements to existing facilities.

9.   Environmental Liability

From time to time, environmental laws, regulations and compliance programs may require changes in the Company’s operations and facilities and may increase the cost of natural gas service.

The Massachusetts Department of Environmental Protection and U.S. Environmental Protection Agency have notified the Company that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at three waste sites.  These sites are listed on the Massachusetts Confirmed Disposal Site List.  In 1990, the DPU issued a generic ruling on cost recovery for environmental cleanup with respect to former gas manufacturing sites.  Under the ruling, the Company will recover prudently incurred annual cleanup costs, excluding carrying costs and an allowance for deferred tax benefits, over a seven-year period through the LDAC.  This ruling also provides for the sharing of any proceeds received from insurance carriers equally between the Company and its ratepayers, and establishes maximum amounts that can be recovered from customers in any one year.

It is anticipated that through 2023 the level of expenditures for the sites will range from $5,580 to $15,975.  The Company has recorded as a liability the most likely cost of $8,830 at December 31, 2010 and $7,280 at December 31, 2009.  The Company recorded a corresponding regulatory asset since the company believes that it is probable that costs incurred will be recovered through rates using the formula discussed above.  The Company's unamortized costs, which were recognized as a regulatory asset, were $5,668 and $6,583 at December 31, 2010 and 2009, respectively.  The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations.  Berkshire’s environmental liabilities are recorded on an undiscounted basis.

22

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

10.   Fair Value of Financial Instruments

The carrying amounts and estimated fair values of the Company’s long-term debt are shown in the following table.  The fair values are based on quoted market prices for the same or similar issues of the same remaining maturities.

	2010				2009
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
First Mortgage Bond-Series P	$	10,000	$	13,500	$	10,000	$	12,181
Various Long-Term Debt		35,681		32,310		30,000		34,225
	$	45,681	$	45,810	$	40,000	$	46,406

The carrying amounts for cash and cash equivalents, accounts receivables and unbilled revenues, net 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.

11.   Lease Obligations

Berkshire Gas has lease arrangements for data processing equipment, office equipment, office space and land.

Operating leases, which are charged to operating expense, consist principally of leases of office space and facilities, land and a wide variety of equipment.  The future minimum lease payments under these operating leases are estimated to be as follows:

2011	$	59
2012		52
2013		17
2014		15
2015		-
	$	143

23

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

12.   Retirement Benefits

Berkshire Gas has a noncontributory funded retirement income plans covering substantially all employees.  The cost of the plans is actuarially determined, and it is the Company's policy to fund accrued pension costs.  The Company uses a December 31 measurement date for its pension plans.

	Successor			Predecessor
	November			January 1,
	17, through			through
	December 31,			November 16,
Pension obligations and funded status	2010			2010			2009
Change in benefit obligation
Benefit obligation beginning balance	$	35,162		$	29,845		$	27,873
Service cost		58			532			514
Interest cost		146			1,585			1,693
Amendments		-			336			-
Actuarial (gain) loss		(1,585	)		3,886			999
Special termination benefits		-			175			-
Benefits paid		(112	)		(1,197	)		(1,234	)
Benefit obligation ending balance		33,669			35,162			29,845
Change in plan assets
Fair value of plan assets at beginning of period		29,809			30,293			26,242
Actual return on plan assets		2,883			752			5,284
Adjustment		-			(39	)		-
Benefits paid		(112	)		(1,197	)		(1,233	)
Fair value of plan assets at end of period		32,580			29,809			30,293
Over (under) funded status at end of period	$	(1,089	)	$	(5,353	)	$	448

	Pension Benefits
	December 31,
	2010			2009
Amounts recognized in the balance sheet
Non current assets	$	456		$	1,362
Non current liabilities		(1,545	)		(914	)
	$	(1,089	)	$	448

The Prepaid Benefit Cost is $-0- and $1,362 at December 31, 2010 and 2009, respectively.

24

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

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 benefit pension plans.  Amounts recognized as regulatory assets or regulatory liabilities consist of:

	Pension Benefits
	December 31,
	2010			2009
Amounts recognized in regulatory assets
Net (gain) loss	$	(4,256	)	$	16,325
Prior service cost		-			26
	$	(4,256	)	$	16,351

Our accumulated benefit obligation for the defined benefit pension plans was $31 and $27 million at December 31, 2010 and 2009, respectively.

Both the projected benefit obligation and the accumulated benefit obligation exceeded the fair value of pension plan assets of the Berkshire Gas’ plans as of December 31, 2010 and 2009.  The following table shows the aggregate projected and accumulated benefit obligations and the fair value of plan assets for Berkshire’s plans for the relevant periods.

	December 31,
	2010		2009
Projected benefit obligation	$	18,197	$	16,468
Accumulated benefit obligation		16,676		14,795
Fair value of plan assets		16,651		15,553

25

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

Components of net periodic benefit cost and other amounts recognized in regulatory assets and regulatory liabilities:

	Successor			Predecessor
	November 17,			January 1,
	Through			Through
	December 31,			November 16,
Pension Benefits	2010			2010			2009
Net periodic benefit cost
Service cost	$	58		$	532		$	514
Interest cost		146			1,585			1,693
Expected return on plan assets		(211	)		(2,749	)		(3,043	)
Amortization of prior service cost		-			4			62
Amortization of net loss		-			789			555
Special termination benefit charge		-			175			-
Net periodic benefit income (costs)		(7	)		336			(219	)
Other changes in plan assets and benefit
obligations recognized in regulatory
assets and regulatory liabilities
Net (gain) loss		(4,256	)		5,922			(1,243	)
Prior service cost		-			336			-
Amortization of net loss		-			(789	)		(554	)
Amortization of prior service cost		-			(4	)		(62	)
Total recognized in regulatory assets
and regulatory liabilities		(4,256	)		5,465			(1,859	)
Total recognized in net periodic benefit
costs and regulatory assets and
regulatory liabilities	$	(4,263	)	$	5,801		$	(2,078	)

Net periodic benefit (income) loss is included in other operating expenses.

There are no amounts of net gains, losses or prior service costs that are expected to be amortized from regulatory assets or regulatory liabilities into net periodic costs for the fiscal year ending December 31, 2011.

We expect that no pension benefit or postretirement benefit plan assets will be returned to us during the fiscal year ended December 31, 2011.

	Pension Benefits
	2010			2009
Weighted-average assumptions used to
determine benefit obligations at December 31
Discount rate		5.30	%		5.80	%
Rate of compensation increase		3.50	%		4.00	%

26

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

As of December 31, 2010, we decreased our discount rate from 5.80% to 5.30%.  The discount rate is the rate at which the benefit obligations could presently be effectively settled.  We determined the discount rate 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.

	Pension Benefits
	2010			2009
Weighted-average assumptions used to determine
net periodic benefit cost net periodic benefit cost
years ended December 31
Discount rate		5.00	%		6.10	%
Expected long-term return on plan assets		8.50	%		8.75	%
Rate of compensation increase		4.00	%		4.00	%

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.  That analysis considered current capital market conditions and projected conditions.  Berkshire amortizes unrecognized actuarial gains and losses either over 10 years from the time they are incurred or 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’ average remaining service to retirement.

Plan Assets

The Company’s share of the pension benefit plan assets were transferred as part of the acquisition on November 17, 2010.  UIL Holdings is responsible for the oversight and management of these assets and has engaged BNY Mellon as the trustee and investment manager to assist in areas of asset allocation and rebalancing, portfolio strategy implementation, and performance monitoring and evaluation.  Target allocations are currently being developed for the long-term.  In the interim, the assets have been invested in index funds which are approximately 50% equities and 50% fixed income instruments.  The governance process is similar to that of the UI Pension Plan assets, including oversight by the Retirement Benefits Plans Investment Committee of the Board of Directors in conjunction with management.

The fair value of the pension assets related to Berkshire Gas Company as of December 31, 2010 was $32,580 and was Level 1 pension assets invested exclusively in Mutual Funds.  The determination of fair value of the Level 1 pension assets was based on quoted prices, as of December 31, 2010.  Changes in the fair value of pension benefits are accounted for in accordance with ASC 715 Compensation – Retirement Benefits.

As of December 2009,our pension benefits plan assets were 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.  Our primary investment objective is to ensure that current and future benefits obligations are adequately funded and with volatility commensurate with our tolerance for risk.  Preservation of capital and achievement of sufficient total return to fund accrued and future benefits obligations are of highest concern.  Our primary means for achieving capital preservation is through diversification of the trust’s investments while avoiding significant concentrations of risk in any one area of the

27

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

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.

Our asset allocation policy was the most important consideration in achieving our objective of superior investment returns while minimizing risk.  We established a target asset allocation policy within allowable ranges for our 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 were 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 were 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 were in domestic securities.  Other, alternative investment targets were 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, increased the probability that the annualized return on the investments was enhanced, while realizing lower overall risk.

Berkshire Gas Company’s allocation of the fair values of Iberdrola USA consolidated pension benefits plan assets at December 31, 2009, by asset category are shown in the following table:

			Fair Value Measurements at
			December 31, 2009, Using
			Quoted Prices
			in Active		Significant		Significant
			Markets for		Observable		Unobservable
			Identical Assets		Inputs		Inputs
	Total		(Level 1)		(Level 2)		(Level 3)
Asset Category
Cash and cash equivalents	$	512	$	11	$	501	$	-
U.S. government securities		666		666		-		-
Common stocks		13,451		13,414		37		-
Registered investment companies		1,602		1,602		-		-
Corporate bonds		4,898		-		4,898		-
Preferred stocks		92		92		-		-
Common/collective trusts		4,814		-		840		3,974
Partnership/joint venture interests		1,252		-		-		1,252
Real estate investments		545		-		-		545
Other investments, principally annuity
and fixed income		2,461		279		420		1,762
	$	30,293	$	16,064	$	6,696	$	7,533

Valuation techniques

We value our pension benefits plan assets as follows:

·   Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value.

·   Level 2: propriety cash associated with other investments bases on yields currently available on comparable securities with similar credit ratings.

28

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

• 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.

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3) Unobservable Inputs (Level 3)
				Common/			Partnership/
	Corporate			Collective			Joint Venture			Real Estate			Other
	Bonds			Trusts			Interests			Investments			Investments			Total
Balance at December 31, 2008	$	2		$	5,974		$	1,474		$	810		$	2,154		$	10,414
Actual return on plan assets
Relating to assets still held at the reporting date		-			35			35			-			-			70
Relating to assets sold during the year		-			1,551			53			(267	)		-			1,337
Purchases, sales and settlements		(2	)		(3,480	)		(275	)		18			(345	)		(4,084	)
Transfers into and/or out of Level 3		-			-			-			-			-			-
Balance at December 31, 2009		-			4,080			1,287			561			1,809			7,737
Transfers into and/or out of Level 3		-			(4,080	)		(1,287	)		(561	)		(1,809	)		(7,737	)
Balance at December 31, 2010	$	-		$	-		$	-		$	-		$	-		$	-

Cash Flows

Contributions

The Company does not expect to contribute to its pension plan in 2011.

29

The Berkshire Gas Company

Notes to Financial Statements

December 31, 2010 and 2009

(in thousands of dollars)

Expected Future Benefit Payments

Expected benefit payments, which reflect expected future service, as appropriate, are:

2011	$	1,435
2012		1,645
2013		1,744
2014		1,852
2015		1,966
2016–2020		11,490

401k Plan

The Company maintains a 401(k) Post-Retirement Plan for all Company employees.  The Company matches up to 3.5% of a participating employee's annual salary.  The expense related to the 401(k) Plan was $175 through November 16, 2010, $21 from November 17, 2010 through December 31, 2010 and $187 for the year ended December 31, 2009, respectively.

 30

EX-99.5

EXHIBIT 99.5

FINANCIAL STATEMENTS

OF

THE UNITED ILLUMINATING COMPANY

AS OF AND FOR THE THREE MONTHS ENDED

MARCH 31, 2011 AND 2010

(UNAUDITED)

TABLE OF CONTENTS

	Page
	Number
Financial Statements:
Statement of Income for the three months ended March 31, 2011 and 2010	3
Balance Sheet as of March 31, 2011 and 2010	4
Statement of Cash Flows for the three months ended March 31, 2011 and 2010	6
Statement of Changes in Shareholders’ Equity	7
Notes to the Financial Statements	8

2

THE UNITED ILLUMINATING COMPANY
STATEMENT OF INCOME
(In Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2011			2010
Operating Revenues	$	198,226		$	220,276
Operating Expenses
Operation
Purchased power		49,263			75,348
Operation and maintenance		56,338			51,402
Transmission wholesale		17,022			15,476
Depreciation and amortization		24,286			27,241
Taxes - other than income taxes		18,263			17,704
Total Operating Expenses		165,172			187,171
Operating Income		33,054			33,105
Other Income and (Deductions), net (Note H)		5,621			3,846
Interest Charges, net
Interest on long-term debt		10,099			8,932
Other interest, net		(58	)		292
		10,041			9,224
Amortization of debt expense and redemption premiums		413			371
Total Interest Charges, net		10,454			9,595
Income Before Income Taxes, Equity Earnings		28,221			27,356
Income Taxes (Note E)		11,858			10,717
Income Before Equity Earnings		16,363			16,639
Income from Equity Investments		2,062			8
Net Income	$	18,425		$	16,647
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

3

THE UNITED ILLUMINATING COMPANY
BALANCE SHEET
ASSETS
(In Thousands)
(Unaudited)
	March 31,		March 31,
	2011		2010
Current Assets
Unrestricted cash and temporary cash investments	$	6,957	$	5,174
Restricted cash		3,636		1,338
Utility accounts receivable less allowance of $3,400 and $4,500, respectively		96,330		89,398
Other accounts receivable		11,283		11,373
Unbilled revenues		36,900		40,281
Current regulatory assets		40,876		48,066
Deferred income taxes		20,607		4,796
Current portion of derivative assets (Note A), (Note K)		6,886		3,304
Other current assets		14,006		12,372
Total Current Assets		237,481		216,102
Other investments
Equity investment in Related Party (Note H)		64,842		1
Other		8,485		7,688
Total Other investments		73,327		7,689
Net Property, Plant and Equipment		1,377,082		1,175,097
Regulatory Assets (future amounts due from customers through the ratemaking process)		634,319		600,321
Deferred Charges and Other Assets
Unamortized debt issuance expenses		7,084		6,627
Related party note receivable (Note H)		62,483		114,423
Other long-term receivable		1,281		1,284
Derivative assets (Note A), (Note K)		43,470		27,546
Other		7,468		422
Total Deferred Charges and Other Assets		121,786		150,302
Total Assets	$	2,443,995	$	2,149,511
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

4

LIABILITIES AND CAPITALIZATION
(In Thousands)
(Unaudited)
	March 31,			March 31,
	2011			2010
Current Liabilities
Line of credit borrowings		24,000			7,000
Current portion of long-term debt		62,283			54,426
Accounts payable		92,023			73,257
Dividends payable		19,300			14,400
Accrued liabilities		32,253			27,209
Current regulatory liabilities		42,422			13,505
Interest accrued		8,282			7,416
Taxes accrued		(19,464	)		38,592
Current portion of derivative liabilities (Note A), (Note K)		19,908			3,627
Total Current Liabilities		281,007			239,432
Noncurrent Liabilities
Pension accrued		124,801			142,420
Connecticut Yankee contract obligation		16,474			20,081
Other post-retirement benefits accrued		52,706			48,052
Derivative liabilities (Note A), (Note K)		185,902			96,263
Other		21,895			6,679
Total Noncurrent Liabilities		401,778			313,495
Deferred Income Taxes (future tax liabilities owed to taxing authorities)		350,094			275,306
Regulatory Liabilities (future amounts owed to customers through the ratemaking process)		73,108			81,803
Commitments and Contingencies (Note J)
Capitalization (Note B)
Long-term debt, net of unamortized discount and premium		670,460			630,457
Common Stock Equity
Common stock		1			1
Paid-in capital		529,730			469,730
Retained earnings		137,817			139,287
Net Common Stock Equity		667,548			609,018
Total Capitalization		1,338,008			1,239,475
Total Liabilities and Capitalization	$	2,443,995		$	2,149,511
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

5

THE UNITED ILLUMINATING COMPANY
STATEMENT OF CASH FLOWS
(In Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2011			2010
Cash Flows From Operating Activities
Net income	$	18,425		$	16,647
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization		24,699			27,612
Deferred income taxes		11,629			(4,874	)
Stock-based compensation expense (Note A)		1,658			1,128
Pension expense		6,968			6,019
Undistributed (earnings) in equity investments		(2,062	)		(8	)
Excess generation service charge		(1,423	)		(10,434	)
Deferred transmission expense		6,608			5,398
Other non-cash items, net		(4,362	)		112
Changes in:
Utility accounts receivable, net		(4,015	)		(10,542	)
Unbilled revenues and other accounts receivable		6,498			8,093
Prepayments		(5,729	)		(4,031	)
Accounts payable		(6,428	)		(7,396	)
Interest accrued		(2,628	)		119
Taxes accrued		(1,263	)		24,285
Accrued liabilities		(10,523	)		(5,945	)
Accrued pensions		(39,928	)		(320	)
Other assets		36			256
Other liabilities		2,337			371
Total Adjustments		(17,928	)		29,843
Net Cash provided by Operating Activities		497			46,490
Cash Flows from Investing Activities
Related party note receivable (Note H)		(500	)		(6,650	)
Plant expenditures including AFUDC debt		(75,220	)		(46,703	)
Changes in restricted cash		(1,237	)		2,357
Net Cash (used in) Investing Activities		(76,957	)		(50,996	)
Cash Flows from Financing Activities
Equity infusion from parent		60,000			-
Debt borrowings, net of discount		500			6,650
Line of credit borrowings (repayments), net		24,000			7,000
Payment of common stock dividend		(13,300	)		(9,000	)
Other		-			(318	)
Net Cash provided by Financing Activities		71,200			4,332
Unrestricted Cash and Temporary Cash Investments:
Net change for the period		(5,260	)		(174	)
Balance at beginning of period		12,217			5,348
Balance at end of period		6,957			5,174
Non-cash investing activity:
Plant expenditures included in ending accounts payable	$	31,718		$	17,036
The accompanying Notes to Financial
Statements are an integral part of the financial statements.

6

THE UNITED ILLUMINATING COMPANY
STATEMENT OF CHANGES IN SHAREHOLDER'S EQUITY
March 31, 2011 and 2010
(Thousands of Dollars)
(Unaudited)
	Common Stock				Paid-in		Retained
	Shares		Amount		Capital		Earnings			Total
Balance as of March 31, 2009		100	$	1	$	388,221	$	131,954		$	520,176
Net income								60,733			60,733
Cash dividends								(53,400	)		(53,400	)
Equity infusion from parent						81,000					81,000
Allocation of benefits - ESOP						509					509
Balance as of March 31, 2010		100	$	1	$	469,730	$	139,287		$	609,018
Net income								65,530			65,530
Cash dividends								(67,000	)		(67,000	)
Equity infusion from parent						60,000					60,000
Balance as of March 31, 2011		100	$	1	$	529,730	$	137,817		$	667,548
The accompanying Notes to the Financial Statements are an integral part of the financial statements.

7

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED)

(A)   BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES

The United Illuminating Company (UI), a wholly owned subsidiary of UIL Holdings Corporation (UIL Holdings), is a regulated operating electric public utility established in 1899. It is engaged principally in the purchase, transmission, distribution and sale of electricity for residential, commercial and industrial purposes.

UI is also a 50-50 joint venturer, together with NRG Energy, Inc. (NRG), in GenConn Energy LLC (GenConn), a project selected to build and operate new peaking generation plants to help address Connecticut’s need for power generation during the heaviest load periods.

Accounting Records

The accounting records of UI are maintained in conformity with accounting principles generally accepted in the United States of America (GAAP).

The accounting records for UI are also maintained in accordance with the uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and the DPUC.

Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to use estimates and assumptions that affect (1) the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and (2) the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Certain immaterial amounts that were reported in the Balance Sheet and Statement of Cash Flows in previous periods have been reclassified to conform to the current presentation.

8

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

Regulatory Accounting

UI’s regulatory assets and liabilities as of March 31, 2011 and 2010 included the following:

	Remaining	March 31,		March 31,
	Period	2011		2010
		(In Thousands)
Regulatory Assets:
Nuclear plant investments – above market	(a)	$	288,277	$	308,722
Income taxes due principally to book-tax differences	(b)		9,427		37,640
Connecticut Yankee	5 years		16,474		20,081
Unamortized redemption costs	11 to 23 years		13,507		14,310
Pension and other post-retirement benefit plans	(c)		171,279		165,010
Contracts for differences	(d)		155,522		75,274
Excess generation service charge	(e)		10,135		-
Deferred Pension and post-retirement expense			-		8,618
Other	(b)		10,574		18,732
Total regulatory assets			675,195		648,387
Less current portion of regulatory assets			40,876		48,066
Regulatory Assets, Net		$	634,319	$	600,321
Regulatory Liabilities:
Accumulated deferred investment tax credits	33 years	$	4,868	$	5,014
Deferred gain on sale of property	(a)		37,798		37,798
Middletown/Norwalk local transmission network service collections	40 years		22,978		23,551
Pension and other post-retirement benefit plans	4 to 8 years		3,303		524
Deferred transmission expense	(f)		33,644		-
Excess generation service charge	(e)		-		9,072
Other	(b)		12,939		19,349
Total regulatory liabilities			115,530		95,308
Less current portion of regulatory liabilities			42,422		13,505
Regulatory Liabilities, Net		$	73,108	$	81,803

(a) Asset/Liability relates to the Competitive Transition Assessment (CTA).  Total CTA costs recovery is currently projected to be completed in 2015, with stranded cost amortization expected to end in 2013.

(b) Amortization period and/or balance vary depending on the nature, cost of removal and/or remaining life of the underlying assets/liabilities.

(c) Asset life is dependent upon timing of final pension plan distribution; balance is recalculated each year in accordance with ASC 715 "Compensation-Retirement Benefits" (Note G).

(d) Asset life is equal to delivery term of related contracts (which vary from approximately 9 - 16 years); balance fluctuates based upon quarterly market analysis performed on the related derivatives (Note K).

(e) Working capital allowance for generation service charge; this amount fluctuates based upon cash inflows and outflows in a given period.

(f) Regulatory asset or liability which defers transmission income or expense and fluctuates based upon actual revenues and revenue requirements.

Derivatives

UI is party to contracts and involved in transactions that have been determined to be derivatives and are discussed below.

The fair value of the gross derivative assets and liabilities as of March 31, 2011 and 2010 were as follows:

9

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

	March 31, 2011
	(In Thousands)
			Deferred Charges		Current			Noncurrent
	Current Assets		and Other Assets		Liabilities			Liabilities
Derivative assets/(liabilities), gross	$	6,886	$	43,470	$	(19,908	)	$	(185,902	)
	March 31, 2010
	(In Thousands)
			Deferred Charges		Current			Noncurrent
	Current Assets		and Other Assets		Liabilities			Liabilities
Derivative assets/(liabilities), gross	$	3,304	$	27,546	$	(3,627	)	$	(96,263	)

Contracts for Differences (CfDs)

As directed by the Connecticut Department of Public Utility Control (DPUC), UI and CL&P each executed two CfDs.  The cost of the contracts will be paid by customers and will be subject to a cost-sharing agreement whereby approximately 20% of the cost is borne by UI customers and approximately 80% by CL&P customers.  As of March 31, 2011, UI has recorded the following amounts in the accompanying Balance Sheet related to its CfDs:  a gross derivative asset of $50.3 million, a regulatory asset of $155.5 million and a gross derivative liability of $205.8 million ($142.8 million of which related to its portion of CL&P’s derivative liabilities).  See Note (K) “Fair Value Measurements” for additional CfD information.

On February 7, 2010, an explosion occurred at the construction site of a 620-megawatt plant being built by Kleen Energy Systems, LLC (Kleen), one of four capacity resources selected in 2008 by the DPUC to create new or incremental capacity resources.  CL&P has executed the CfD with the Kleen project which is subject to the cost-sharing agreement between UI and CL&P.  Kleen reports that it continues to rebuild its facility and on April 15, 2011, in its quarterly progress report, reported that commercial operation of the facility will commence on or about June 1, 2011, at which time payments under the CfD will begin.

During 2010, UI adjusted a probability assumption in its expected cash flow analysis based on management’s assessment of the probability of the project reaching commercial operation which significantly reduced the fair value of the related regulatory asset and derivative liability on its Balance Sheet.  Subsequent increases to the same assumption in 2010 and 2011 have resulted in a corresponding increase in the related regulatory asset and derivative liability.  These changes did not have an impact on UI’s Statement of Income.

10

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

The unrealized gains and losses from mark-to-market adjustments to derivatives recorded in regulatory assets or regulatory liabilities for the three month periods ended March 31, 2011 and 2010 were as follows:

	Three Months Ended
	March 31,
	2011		2010
	(In Thousands)
Regulatory Assets - Derivative liabilities	$	40,161	$	(62,456	)
Regulatory Liabilities - Derivative assets	$	6,332	$	98

The adjustments to the expected cash flow analysis, as discussed above, resulted in changes in UI’s projected derivative liability relating to CL&P’s CfD with Kleen.  The changes in this derivative liability were the primary reasons for the unrealized loss during the three month period ended March 31, 2011.

Stock-Based Compensation

Pursuant to the UIL Holdings 2008 Stock and Incentive Compensation Plan (2008 Stock Plan), a target amount of 111,230 performance shares was granted to certain members of management in February 2011; the average of the high and low market price on the date of grant was $30.69 per share.  Such shares vest at the end of three years.

Total UI stock-based compensation expense for the three month periods ended March 31, 2011 and 2010 was $1.7 million and $1.1 million, respectively.

Variable Interest Entities

UI has identified Connecticut Yankee Atomic Power Company (Connecticut Yankee) and GenConn as variable interest entities (VIEs), which were not subject to consolidation as UI is not the primary beneficiary because it does not have a controlling financial interest, as defined in ASC 810 “Consolidation,” in either VIE.  For further discussion of GenConn, see Note (C) “Regulatory Proceedings –Equity Investment in Peaking Generation.”  For further discussion of Connecticut Yankee, see Note (J) “Commitments and Contingencies.”

Income Taxes

Effective January 1, 2011, UI changed its method of accounting for income taxes for interim reporting periods from the discrete-period approach to the estimated annual effective tax rate approach as defined in ASC 740 “Income Taxes.”.  The change conforms the methodology for determining income taxes for interim periods for UIL Holdings and all of its subsidiaries.  The change in accounting will be reflected in the interim financial statements through retrospective application and does not impact annual reporting.

(B)  CAPITALIZATION

Common Stock

UI had 100 shares of common stock; no pare value, outstanding as of March 31, 2011 and 2010.

11

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

Long-Term Debt

As of March 31, 2011, borrowings under the existing credit facility (EBL) used by UI to fund its commitments as 50% owner of GenConn were $62.3 million.  The remaining balance under the EBL must be repaid upon the earlier of its maturity date or the attainment of commercial operation for GenConn Middletown.  The original maturity date of the loan was April 19, 2011, but was extended to July 31, 2011.

(C)  REGULATORY PROCEEDINGS

Rates

In rulings throughout 2009, the DPUC issued its final decision regarding UI’s application requesting an increase in distribution rates (the 2009 Decisions), the results of which provided for an allowed distribution return on equity of 8.75%, a decrease from the previously approved 9.75%, and a capital structure of 50% equity and 50% debt, compared to the previously approved 48% equity and 52% debt capital structure.  The 2009 Decisions continued the prior earnings sharing mechanism structure, applying to the new 8.75% allowed return, whereby 50% of any earnings over the allowed twelve month level is returned to customers and 50% is retained by UI.  Additionally, the 2009 Decisions provided for a two year pilot program for full decoupling of distribution revenues from sales.

On April 1, 2010, UI filed its ratemaking proposal and underlying decoupling analysis for the 2009 rate year ended February 3, 2010.  On September 1, 2010, the DPUC issued its final decision in this matter approving a decoupling charge totaling approximately $1.6 million to be recovered from ratepayers over a twelve month period commencing in October 2010.  In addition to the decoupling charge, the DPUC also approved a pension and earnings sharing over-recovery credit totaling approximately $3.6 million to be refunded to ratepayers over the same twelve month period commencing in October 2010.  The DPUC also approved the continuance of the decoupling pilot program beyond the 2010 rate year and until such time that a final decision is reached regarding whether to continue, modify or terminate the decoupling mechanism.  UI expects such determination to be made in connection with UI’s 2010 rate year decoupling results, which were filed with the DPUC on April 4, 2011.

In December 2010, UI received a letter ruling approving rates effective January 1, 2011 incorporating the above mentioned distribution rate changes along with previously approved changes to the Generation Services Charges (GSC), Non-Bypassable Federally Mandated Congestion Charges, transmission and systems benefits charges.  Additionally, last resort service GSC rates have been approved for the period through June 30, 2011.

Power Supply Arrangements

UI has wholesale power supply agreements in place for the supply of all of its standard service customers for all of 2011, 60% for 2012 and 10% for 2013.  Supplier of last resort service is procured on a quarterly basis.  UI determined that its contracts for standard service and supplier of last resort service are derivatives under ASC 815 “Derivatives and Hedging” and also qualify for the “normal purchase, normal sale” exception under ASC 815.  As such, UI regularly assesses the accounting treatment for its power supply contracts.  These wholesale power supply agreements contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt was to fall below investment grade.  In October 2010, Moody’s Investor Services released its updated credit opinion for UI and maintained its Baa2 rating with a stable outlook.  In October 2010, Standard & Poor’s released its updated credit opinion for UI, maintaining its BBB rating with a stable outlook.  If UI’s credit rating were to decline one rating and UI were to be placed on negative credit watch, monthly amounts due and payable to the power suppliers would be accelerated to semi-monthly payments.  UI’s credit rating would have to decline two ratings to fall below investment grade at either rating service.  If this were to occur, UI would have to deliver collateral security in an amount equal to the receivables due to the sellers for the thirty day period immediately preceding the default notice.  If such a situation had been in effect as of March 31, 2011, UI would have had to post approximately $13.6 million in collateral.

12

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

New England East-West Solution

Pursuant to an agreement with CL&P (the Agreement), UIhas the right to invest in, and own transmission assets associated with the Connecticut portion of CL&P’s New England East West Solution (NEEWS) projects to improve regional energy reliability.  NEEWS consists of four inter-related transmission projects being developed by subsidiaries of Northeast Utilities (NU), the parent company of CL&P, in collaboration with National Grid USA.  Three of the projects have portions sited in Connecticut:  (1) the Greater Springfield Reliability Project, (2) the Interstate Reliability Project and (3) the Central Connecticut Reliability Project.  Recently NU informed UI that it will be revising its cost estimate for the Connecticut portion of these projects.  Previously NU had projected that the cost of the Connecticut portion of these projects would be approximately $828 million.  UI will update its projected investment once the revised estimate is provided by NU.

Under the terms of the Agreement, UI has the option to make quarterly deposits to CL&P in exchange for ownership of specific transmission assets as they are placed in service.  UI has the right to invest up to the greater of $60 million or an amount equal to 8.4% of CL&P’s costs for the Connecticut portions of the NEEWS projects.  Based upon NU's previously projected costs, UI had expected this amount to approximate $69 million.  As assets are placed in service, CL&P will transfer title to certain transmission assets to UI in proportion to its investments, but CL&P will continue to maintain these portions of the transmission system pursuant to an operating and maintenance agreement with UI.  Also, under the terms of the Agreement, there are certain circumstances under which CL&P can terminate the Agreement, but such termination would not affect assets previously transferred to UI.

Through March 31, 2011, UI has made deposits totaling $7.2 million in NEEWS and expects to make the remaining investments over a period of three to five years, depending on the timing and amount of CL&P’s capital expenditures and the projects’ in service dates.

Equity Investment in Peaking Generation

UI is a 50-50 joint venturer with NRG in GCE Holding LLC, whose wholly owned subsidiary, GenConn, was chosen by the DPUC to build and operate two new peaking generation plants to help address Connecticut’s need for power generation during the heaviest load periods.  The two new peaking generation projects are located at NRG’s existing Connecticut plant locations in Devon and Middletown.  The DPUC has approved 2011 revenue requirements for the GenConn Devon facility of $36.8 million for the period of January 1, 2011 through December 31, 2011 and for the GenConn Middletown facility of $22.6 million for the period of June 1, 2011 through December 31, 2011.  UI’s income from its equity investment in GenConn was $2.1 million and zero for the three month periods ended March 31, 2011 and 2010, respectively.

(D)  SHORT-TERM CREDIT ARRANGEMENTS

As of March 31, 2011, there was $24.0 million outstanding under the revolving credit agreement, dated as of November 17, 2010, entered into by and among UIL Holdings and its regulated subsidiaries including UI, together with a group of banks named therein (the Credit Facility).  Under the Credit Facility, UI has a standby letter of credit outstanding in the amount of $0.4 million which expires on December 31, 2011.  Available credit under the Credit Facility at March 31, 2011 totaled $225.6 million for UI.  UI records borrowings under the Credit Facility as short-term debt, but the Credit Facility provides for longer term commitments from banks allowing UI to borrow and reborrow funds, at its option, until its expiration on November 17, 2014, thus affording UI flexibility in managing its working capital requirements.

13

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

(E) INCOME TAXES

	Three Months Ended
	March 31,
	2011			2010
Income tax expense (benefit) consists of:
Current
Federal	$	1,340		$	13,076
State		(1,074	)		2,549
Total current		266			15,208
Deferred
Federal		9,264			(3,220	)
State		2,365			(1,651	)
Total deferred		11,629			(4,871	)
Investment tax credits		(37	)		(37	)
Total income tax expense	$	11,858		$	10,717

The combined statutory federal and state income tax rate for UI during the three month periods ended March 31, 2011 and 2010 was 40.4%.

Differences in the treatment of certain transactions for book and tax purposes occur which cause the rate of UI’s reported income tax expense to differ from the statutory tax rate described above.  The effective book income tax rate for both the three month periods ended March 31, 2011 and March 31, 2010 was 39.2%.

14

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

(G)  PENSION AND OTHER BENEFITS

The United Illuminating Company Pension Plan (the UI Pension Plan) covers the majority of employees of UIL Holdings and UI.  UI also has a non-qualified supplemental pension plan for certain employees and a non-qualified retiree-only pension plan for certain early retirement benefits.  During the three months ended March 31, 2011, UIL Holdings contributed $39.9 million to the UI Pension Plan.  Additional contributions during the remainder of 2011 are expected to be approximately $12.0 million.

UI has established a supplemental retirement benefit trust and through this trust purchased life insurance policies on certain officers of UI to fund the future liability under the non-qualified supplemental plan.  The cash surrender value of these policies is included in “Other investments” on the Balance Sheet.

The following tables represent the components of net periodic benefit cost for pension and other postretirement benefits (OPEB) for the three month periods ended March 31, 2011 and 2010:

	Three Months Ended March 31,
	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	1,849		$	1,780		$	358		$	340
Interest cost		5,299			5,272			962			982
Expected return on plan assets		(5,474	)		(4,767	)		(426	)		(438	)
Amortization of:
Prior service costs		161			162			(25	)		(26	)
Transition obligation  (asset)		-			-			255			265
Actuarial (gain) loss		3,507			3,078			502			488
Net periodic benefit cost	$	5,342		$	5,525		$	1,626		$	1,611

The following actuarial weighted-average assumptions were used in calculating net periodic benefit cost for the three month periods ended March 31, 2011 and 2010:

	Three Months Ended March 31,
	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
Discount rate		5.10%-5.35	%		5.65%-5.85	%		5.30	%		5.80	%
Average wage increase		3.80	%		3.80	%		N/A			N/A
Return on plan assets		8.25	%		8.50	%		8.25	%		8.50	%
Composite health care trend rate (current year)		N/A			N/A			8.50	%		9.50	%
Composite health care trend rate (2018 forward) (1)		N/A			N/A			5.00	%		5.00	%
(1) For the period ended March 31, 2010, the health care trend rate was applicable for 2019 forward.
N/A – not applicable

15

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

(H)  RELATED PARTY TRANSACTIONS

UI is a 50-50 joint venturer with NRG in GCE Holding LLC, whose wholly owned subsidiary, GenConn, was chosen by the DPUC to build and operate new peaking generation plants to help address Connecticut’s need for power generation during the heaviest load periods.  GenConn had signed a promissory note (the Loan) with UI under which UI advanced up to an aggregate principal amount of $48.5 million to fund GenConn’s construction and other cash needs until permanent financing was arranged.  In connection with the EBL obtained by UI and the project financing obtained by GenConn on April 27, 2009, all outstanding balances on the Loan were replaced by a new promissory note, the balance of which was $62.3 million as of March 31, 2011.  See Note (B) “Capitalization – Long-Term Debt” for further discussion regarding the EBL.  Additionally, $0.5 million and $0.9 million of interest income related to the promissory note are included in “Other Income and (Deductions), net" in the accompanying Statements of Income, for the three month periods ended March 31, 2011 and 2010, respectively,  which is offset by the interest expense incurred by UI under the EBL.

A director of UIL Holdings holds a beneficial interest in the building located at 157 Church Street, New Haven, Connecticut, where UI leases office space.UI’s lease payments for this office space for each of the three month periods ended March 31, 2011 and 2010 totaled $2.6 million and $2.7 million, respectively.

A director of UIL Holdings holds a position on the Board of Directors of People’s United Bank.  UI has a banking relationship with People’s United Bank in connection with the Credit Facility described in Note (D) “Short-Term Credit Arrangements.”  Such Director was not directly involved in any transaction between UI and People’s United Bank.

Inter-company Transactions

UI receives certain services from, and enters into certain inter-company transactions with, UIL Holdings.  Such transactions primarily relate to outside professional services and stock based compensation.  Costs of the services that are allocated amongst UI and UIL Holdings are based on actual direct costs incurred by the respective company, which are settled at the end of each month by way of inter-company billings and wire transfers.  At March 31, 2011 and 2010, the Balance Sheet reflects inter-company receivables of $1.0 million and $0.3 million, respectively, and inter-company payables of $7.8 million and $3.1 million, respectively.

Dividends/Capital Contributions

In 2010 and 2011, UI made wire transfers to UIL Holdings on a quarterly basis, representing an amount approximately equal to UI’s forecasted net income, in order to maintain its capitalization structure as allowed per the 2008 Rate Case.  For the years ended March 31, 2011 and 2010, UI accrued dividends to UIL Holdings of $19.3 million and $14.4 million, respectively.

(J)  COMMITMENTS AND CONTINGENCIES

Connecticut Yankee Atomic Power Company

UI has a 9.5% stock ownership share in the Connecticut Yankee Atomic Power Company (Connecticut Yankee), the carrying value of which was $0.2 million as of March 31, 2011.  In 1996, the Board of Directors of Connecticut Yankee voted unanimously to retire the Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial operation.  Connecticut Yankee updates the cost of its remaining decommissioning activity, which consists primarily of ground water monitoring and nuclear fuel storage, at least annually, and provides UI with a projected recovery schedule depicting annual costs expected to be billed to UI, including a return on investment over the term of the projected recovery period.  The present value of these costs is calculated using UI’s weighted-average cost of capital and, after consideration of recoverability, recorded as a Connecticut Yankee Contract Obligation and a corresponding regulatory asset.  At March 31, 2011, UI has regulatory approval to recover in future rates (through the CTA) its $16.5 million regulatory asset for Connecticut Yankee over a term ending in 2015.

16

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

DOE Spent Fuel Litigation

In the Nuclear Waste Policy Act of 1982, Congress provided for the United States Department of Energy (DOE) to dispose of spent nuclear fuel and other high-level waste (hereinafter Nuclear Waste) from nuclear generating plants.  In 1983, Connecticut Yankee and the DOE entered into a standard disposal contract mandated by the Act which required the DOE to begin disposing of Connecticut Yankee’s Nuclear Waste by the end of January 1998.

In 1998, Connecticut Yankee filed claims in the United States Court of Federal Claims seeking damages resulting from the breach of the 1983 contracts by the DOE.  In September 2010, the Court issued its decision in the remanded case and awarded Connecticut Yankee damages of $39.7 million for its spent fuel-related costs through 2001.  On November 8, 2010, the DOE appealed the decision to the United States Court of Appeals for the Federal Circuit and on November 19, 2010 Connecticut Yankee filed a notice of cross-appeal.  UI’s 9.5% ownership share would result in a payment of approximately $3.8 million which, if awarded, would be refunded to customers.

In December 2007, Connecticut Yankee filed a second set of complaints against the government seeking unspecified damages incurred since January 1, 2002 for the DOE’s failure to remove Connecticut Yankee’s spent fuel.  In July 2009, Connecticut Yankee provided the government with a second set of damage claims totaling approximately $135 million for damages incurred from January 1, 2002 through December 31, 2008.  UI’s 9.5% ownership share would result in a payment of approximately $12.8 million which, if awarded, would be refunded to customers.  As an interim measure until the DOE complies with its contractual obligation to dispose of Connecticut Yankee’s spent fuel, Connecticut Yankee constructed an ISFSI, utilizing dry-cask storage, on the site of the Connecticut Yankee Unit and completed the transfer of its Nuclear Waste to the ISFSI in 2005.

Environmental Concerns

In complying with existing environmental statutes and regulations and further developments in areas of environmental concern, including legislation and studies in the fields of water quality, hazardous waste handling and disposal, toxic substances, climate change and electric and magnetic fields, UI may incur substantial capital expenditures for equipment modifications and additions, monitoring equipment and recording devices, and it may incur additional operating expenses.  The total amount of these expenditures is not now determinable.  Environmental damage claims may also arise from the operations of UI.  Significant environmental issues known to UI at this time are described below.

Site Decontamination, Demolition and Remediation Costs

In November 2010, the EPA made inquiry of UI regarding the storage of PCB materials from the time they were brought to UI’s Shelton, CT facility from the field until their shipment to an authorized disposal facility, from 2006 through June of 2010, and the maintenance of an annual document log in connection with the storage.  On January 14, 2011, the Company filed its response to this inquiry with EPA, setting forth the details of the Company’s PCB management policy and providing annual summaries for the referenced years.  On February 8, 2011, UI received an EPA subpoena requesting additional information concerning the annual summaries provided.  UI has responded to this subpoena.  At this time, UI cannot assess the potential financial impact, if any, of this inquiry.   As such, as of March 31, 2011, no liability related to this matter has been recorded.

In June 2006, UI executed an agreement with the City of Bridgeport and its Redevelopment Authority (the City) for the transfer of title of UI’s Steel Point property to the City.  Pursuant to a Memorandum of Understanding (MOU) among UI, the City of Bridgeport, and the City’s selected developer for the property, the City and developer released UI from any further liability with respect to the Steel Point property after title transferred, and the City and/or developer has indemnified UI for environmental matters related to the Steel Point property.  The Steel Point property includes the land up to the bulkhead.  The MOU provides that there is no indemnity for liability related to contaminated harbor sediments.  UI is not aware of any such claims.  UI would seek to recover any uninsured costs related to such sediments that are UI’s responsibility, to the extent incurred, through the CTA, in accordance with the ratemaking treatment approved in the DPUC’s July 2006 decision.

17

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

A site on the Mill River in New Haven was conveyed by UI in 2000 to an unaffiliated entity, Quinnipiac Energy LLC (QE), reserving to UI permanent easements for the operation of its transmission facilities on the site.  At the time of the sale, a fund of approximately $1.9 million, an amount equal to the then-current estimate for remediation, was placed in escrow for purposes of bringing soil and groundwater on the site into compliance with applicable environmental laws.  Approximately $0.1 million of the escrow fund remains unexpended.  QE has since sold the property to Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat).  UI is unaware of what agreement was reached between QE and Evergreen Power and Asnat regarding future environmental liability or what remediation activity remains to be undertaken at the site.  UI could be required by applicable environmental laws to finish remediating any subsurface contamination at the site if it is determined that QE and/or Evergreen Power and Asnat have not completed the appropriate environmental remediation at the site.  UI has not updated the original $1.9 million remediation estimate, and does not have specific knowledge of any remediation work done, or remaining to be done on behalf of QE or any subsequent owner.  In July 2008, Evergreen Power and Asnat submitted a claim to UI seeking compensation for environmental remediation on the property, including the existing building which remains on the site.   UI cannot presently assess the potential financial impact, if any, of this claim.  As such, as of March 31, 2011, no liability related to this claim has been recorded.

In April 1999, UI completed the sale of its Bridgeport Harbor Station and New Haven Harbor Station generating plants in compliance with Connecticut’s electric utility industry restructuring legislation.  With respect to the portion of the New Haven Harbor Station site that UI retained, UI has performed an additional environmental analysis, indicating that approximately $3.2 million in remediation expenses will be incurred.  Actual remediation costs may be higher or lower than what is currently estimated.  The required remediation is virtually all on transmission-related property and UI has accrued these estimated expenses, which were recovered in transmission rates.

From 1961 to 1976, UI owned a parcel of property in Derby, Connecticut, on which it operated an oil-fired electric generating unit.  For several years, the Connecticut Department of Environmental Protection (CDEP) has been monitoring and remediating a migration of fuel oil contamination from a neighboring parcel of property into the adjacent Housatonic River.  Based on its own investigation to date, UI believes it has no responsibility for this contamination.  If regulatory agencies determine that UI is responsible for the cost of these remediation activities, UI may incur substantial costs, no estimate of which is currently available.

Middletown/Norwalk Transmission Project

The general contractor and two subcontractors responsible for civil construction work in connection with the installation of UI’s portion of the Middletown/Norwalk Transmission Project’s underground electric cable system have filed lawsuits seeking payment for change order requests for approximately $34.5 million, plus interest and costs.  UI intends to defend the litigation.  To the extent that UI is required to satisfy any of the change order requests, UI would seek recovery through its transmission revenue requirement.

GenConn

The former general contractor responsible for the construction at the GenConn Devon facility has submitted change order requests totaling approximately $8.5 million and has asserted a delay and impact claim against GenConn Devon in the amount of approximately $16.9 million.  GenConn Devon is reviewing a report prepared on the contractor's behalf with respect to the delay claim, and will be continuing its review of the change order requests after reviewing the report.  The former general contractor has also claimed approximately $4.9 million as a final payment with respect to its prior work as general contractor for the GenConn Middletown facility.  GenConn Middletown disputed this claim, which was mediated on March 30, 2011.  As a result of such mediation, the parties agreed to settle the claim and have executed and delivered a settlement agreement.  GenConn Middletown has or will pay the agreed upon settlement amount upon satisfaction of certain conditions to be performed by the former general contractor.  To the extent that GenConn is required to pay all or a portion of these claims, as with other capital construction expenditures, GenConn would seek, and expect to recover, associated costs through its annual regulatory proceeding.  To the extent that there is any financial impact on GenConn, the effect on UI’s Financial Statements will be reflected in the carrying value of its 50% ownership position in GenConn and through “Income from Equity Investments” in the Statement of Income.

18

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

In September 2010, UIL Holdings entered into a Sponsor Guaranty and Payment Agreement in favor of the Royal Bank of Scotland PLC, as Administrative Agent under the Project Financing arrangement, whereby UIL Holdings guarantees to pay an amount up to $6 million in respect of amounts related to the former general contractor’s claims and litigation expenses as they relate to such claims described above.  Given the assessment of this claim as described above, no liability has been recorded as of March 31, 2011.

In addition to the borrowings outstanding under the EBL as discussed in Note (B) “Capitalization – Long-Term Debt,” as well as $2.0 million equity investment made on April 21, 2011, UI may be required to make an additional equity investment of up to $7.0 million for the construction of the GenConn Middletown peaking generation facility.

(K) FAIR VALUE MEASUREMENTS

UI utilizes an income approach valuation technique to value the majority of its assets and liabilities measured and reported at fair value.  As required by ASC 820 “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the fair value measurement.  UI’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables set forth UI’s financial assets and liabilities, other than pension benefits and OPEB, which were accounted for at fair value on a recurring basis as of March 31, 2011 and December 31, 2010.

	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total
March 31, 2011	(In Thousands)
Assets:
Derivative assets	$	-	$	-	$	50,356		$	50,356
Deferred Compensation Plan		2,394		-		-			2,394
Supplemental retirement benefit trust life insurance policies (Note G)		5,886		-		-			5,886
	$	8,280	$	-	$	50,356		$	58,636
Liabilities:
Derivative liabilities	$	-	$	-	$	205,810		$	205,810
Net fair value assets/(liabilities), March 31, 2011	$	8,280	$	-	$	(155,454	)	$	(147,174	)
March 31, 2010
Assets:
Derivative assets	$	-	$	-	$	30,850		$	30,850
Deferred Compensation Plan		2,153		-		-			2,153
Supplemental retirement benefit trust life insurance policies (Note G)		5,257		-		-			5,257
	$	7,410	$	-	$	30,850		$	38,260
Liabilities:
Derivative liabilities	$	-	$	-	$	99,890		$	99,890
Net fair value assets/(liabilities), December 31, 2010	$	7,410	$	-	$	(69,040	)	$	(61,630	)

19

THE UNITED ILLUMINATING COMPANY

NOTES TO FINANCIAL STATEMENTS – (UNAUDITED) (Continued)

The determination of fair value of the derivative assets and liabilities, which primarily consist of contracts for differences, was based on a probability-based expected cash flow analysis that was discounted at the March 31, 2011 or December 31, 2010 risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates.  Certain management assumptions were required, including development of pricing that extended over the term of the contracts.  In addition, UI performed an assessment of risks related to obtaining regulatory, legal and siting approvals, as well as obtaining financing resources and ultimately attaining commercial operation.   The DPUC has determined that changes in fair value associated with the contracts for differences are fully recoverable.  As a result, such changes have no impact on UI’s net income.

The fair value of the noncurrent investments available for sale is determined using quoted market prices in active markets for identical assets.  The investments primarily consist of money market funds.

Under the UIL Deferred Compensation Plan (DCP), directors, named executive officers and certain other executives may elect to defer certain elements of compensation.  Participants in the DCP are permitted to direct investments of their elective deferral accounts into ‘deemed’ investments consisting of non-publicly traded mutual funds available through variable insurance products, and Company common stock equivalents.  These investments, which are actively traded in sufficient frequency and volume to provide pricing information on an ongoing basis, are marked-to-market in accordance with ASC 815 based upon such pricing information.

The following tables set forth a reconciliation of changes in the fair value of the assets and liabilities above that are classified as Level 3 in the fair value hierarchy for the three month period ended March 31, 2011.

	Three Months Ended
	March 31, 2011
	(In Thousands)
Net derivative assets/(liabilities), December 31, 2010	$	(108,975	)
Unrealized gains and (losses), net		(46,479	)
Net derivative assets/(liabilities), March 31, 2011	$	(155,454	)

The following table sets forth a reconciliation of changes in the net regulatory asset/(liability) balances that were established to recover any unrealized gains/(losses) associated with the contracts for differences for the three month period ended March 31, 2011.  The amounts offset the net contract for differences liabilities included in the derivative liabilities detailed above.

	Three Months Ended
	March 31, 2011
	(In Thousands)
Net regulatory assets/(liabilities), December 31, 2010	$	108,975
Unrealized (gains) and losses, net		46,479
Net regulatory assets/(liabilities), March 31, 2011	$	155,454

20

EX-99.6

	EXHIBIT 99.6
Connecticut Natural Gas Corporation
Financial Statements (Unaudited)
For the Three Months Ended March 31, 2011 and 2010

Table of Contents
March 31, 2011 and 2010
Financial Statements (Unaudited)	Page(s)
Statements of Income	1
Statements of Comprehensive Income	1
Balance Sheets	2
Statements of Cash Flows	4
Statement of Changes in Common Stock Equity	5

Connecticut Natural Gas Corporation
Statements of Income (Unaudited)
Three months ended March 31,	2011			2010
(Thousands)
Operating Revenues
Sales and services	$	166,253		$	154,285
Operating Expenses
Natural gas purchased		108,656			100,313
Other operating expenses		13,328			14,686
Maintenance		2,092			2,031
Depreciation and amortization		5,846			5,665
Other taxes		8,324			8,302
Total Operating Expenses		138,246			130,997
Operating Income		28,007			23,288
Other (Income)		(428	)		(3,216	)
Other Deductions		1,542			162
Interest Charges, Net		2,965			3,015
Income Before Income Taxes		23,928			23,327
Income Taxes		7,592			9,486
Net  Income		16,336			13,841
Less: Preferred Stock Dividends		13			13
Earnings Available for Common Stock	$	16,323		$	13,828
Connecticut Natural Gas Corporation
Statements of Comprehensive Income
Three months ended March 31,		2011			2010
(Thousands)
Net Income	$	16,336		$	13,841
Other Comprehensive Income (Loss), Net of Tax		12			(8	)
Comprehensive Income	$	16,348		$	13,833

1

Connecticut Natural Gas Corporation
Balance Sheets (Unaudited)
	March 31,		December 31,
	2011		2010
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$	2,174	$	49,520
Accounts receivable and unbilled revenues, net		90,483		70,881
Affiliated accounts receivable		338		964
Affiliated note receivable		29,000		-
Natural gas in storage, at average cost		28,669		54,630
Derivative assets		95		1,625
Accumulated deferred income taxes		1,790		-
Prepayments and other current assets		4,333		6,463
Total Current Assets		156,882		184,083
Utility Plant, at Original Cost
Natural gas		635,722		634,481
Less accumulated depreciation		220,252		216,886
Net Utility Plant in Service		415,470		417,595
Construction work in progress		569		428
Total Utility Plant		416,039		418,023
Other Property and Investments, Net		1,921		1,920
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes		149		3,958
Deferred income taxes		15,508		5,859
Deferred purchased gas costs		-		8,408
Pension and other postretirement benefits		79,070		79,895
Other		53,461		56,372
Total regulatory assets		148,188		154,492
Other assets
Goodwill		115,049		115,068
Other		2,500		2,750
Total other assets		117,549		117,818
Total Regulatory and Other Assets		265,737		272,310
Total Assets	$	840,579	$	876,336

2

Connecticut Natural Gas Corporation
Balance Sheets (Unaudited)
	March 31,			December 31,
	2011			2010
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$	3,915		$	3,915
Accounts payable and accrued liabilities		9,957			8,252
Accounts payable, natural gas purchased		28,588			30,623
Accounts payable to affiliates		640			1,161
Interest accrued		3,572			2,738
Taxes accrued		15,394			9,462
Other		12,317			12,781
Total Current Liabilities		74,383			68,932
Regulatory and Other Liabilities
Regulatory liabilities
Pension and other postretirement benefits		9,921			10,404
Accrued removal obligation		114,172			112,548
Other		31,156			26,573
Total regulatory liabilities		155,249			149,525
Other liabilities
Deferred income taxes		16,742			13,862
Pension and other postretirement benefits		72,833			77,886
Asset retirement obligation		6,857			6,769
Other		4,658			4,862
Total other liabilities		101,090			103,379
Total Regulatory and Other Liabilities		256,339			252,904
Long-term debt		162,827			163,805
Total Liabilities		493,549			485,641
Commitments
Preferred Stock
Preferred stock		750			750
Common Stock Equity
Common stock		33,233			33,233
Capital in excess of par value		350,827			350,827
Retained (deficit) earnings		(37,809	)		5,868
Accumulated other comprehensive income		29			17
Total Common Stock Equity		346,280			389,945
Total Liabilities and  Equity	$	840,579		$	876,336

3

Connecticut Natural Gas Corporation
Statements of Cash Flows (Unaudited)
Three months ended March 31,	2011			2010
(Thousands)
Operating Activities
Net income	$	16,336		$	13,841
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and amortization		5,846			5,665
Amortization of regulatory and other assets and liabilities		3,896			(9,229	)
Deferred  income taxes and investment tax credits deferred, net		(3,292	)		(5,063	)
Pension expense		1,528			1,636
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net		(18,976	)		(21,827	)
Inventories		25,961			29,994
Prepayments and other current assets		3,660			(1,152	)
Accounts payable and accrued liabilities		(851	)		(4,466	)
Interest accrued		834			923
Taxes accrued		5,932			34,907
Other current liabilities		(464	)		1,845
Changes in other assets		11,813			18,924
Changes in other liabilities		(7,960	)		406
Net Cash Provided by Operating Activities		44,263			66,404
Investing Activities
Utility plant additions		(2,595	)		(2,269	)
Loan to parent		(29,000	)		-
Investments, net		(1	)		26
Net Cash Used in Investing Activities		(31,596	)		(2,243	)
Financing Activities
Dividends paid on preferred stock		(13	)		(13	)
Dividends paid on common stock		(60,000	)		(11,000	)
Net Cash Used in Financing Activities		(60,013	)		(11,013	)
Net Increase in Cash and Cash Equivalents		(47,346	)		53,148
Cash and Cash Equivalents, Beginning of Period		49,520			1,747
Cash and Cash Equivalents, End of Period	$	2,174		$	54,895

4

Connecticut Natural Gas Corporation
Statement of Changes in Common Stock Equity (Unaudited)
(Thousands)
										Accumulated
	Common Stock						Retained			Other
	Outstanding $3.125 Par Value				Capital in		Earnings			Comprehensive
	Shares		Amount		Excess of Par		(Deficit)			Income		Total
Balance, January 1, 2011		10,634	$	33,233	$	350,827	$	5,868		$	17	$	389,945
Net income								16,336					16,336
Other comprehensive income, net of tax											12		12
Comprehensive income													16,348
Dividends common stock								(60,000	)				(60,000	)
Dividends preferred stock								(13	)				(13	)
Balance, March 31, 2011		10,634	$	33,233	$	350,827	$	(37,809	)	$	29	$	346,280

 5

EX-99.7

	EXHIBIT 99.7
The Southern Connecticut Gas Company
Financial Statements (Unaudited)
For the Three Months Ended March 31, 2011 and 2010

Table of Contents
March 31, 2011 and 2010
Financial Statements (Unaudited)	Page(s)
Statements of Income	1
Statements of Comprehensive Income	1
Balance Sheets	2
Statements of Cash Flows	4
Statement of Changes in Common Stock Equity	5

The Southern Connecticut Gas Company
Statements of Income (Unaudited)
Three months ended March 31,	2011			2010
(Thousands)
Operating Revenues
Sales and services	$	165,656		$	151,460
Operating Expenses
Natural gas purchased		105,145			90,732
Other operating expenses		17,453			13,568
Maintenance		2,410			2,077
Depreciation and amortization		4,248			4,376
Other taxes		8,249			8,386
Total Operating Expenses		137,505			119,139
Operating Income		28,151			32,321
Other (Income)		(79	)		(152	)
Other Deductions		128			-
Interest Charges, Net		3,583			4,226
Income Before Income Taxes		24,519			28,247
Income Taxes		9,700			11,719
Net Income	$	14,819		$	16,528
The Southern Connecticut Gas Company
Statements of Comprehensive Income
Three months ended March 31,		2011			2010
(Thousands)
Net Income	$	14,819		$	16,528
Other Comprehensive Income, Net of Tax		152			116
Comprehensive Income	$	14,971		$	16,644

1

The Southern Connecticut Gas Company
Balance Sheets (Unaudited)
	March 31,		December 31,
	2011		2010
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$	1,647	$	11,542
Accounts receivable and unbilled revenues, net		95,975		69,684
Affiliated accounts receivable		613		1,256
Natural gas in storage, at average cost		23,935		48,578
Materials and supplies, at average cost		1,055		883
Deferred income taxes		1,919		1,919
Prepaid taxes		1,500		1,853
Prepayments and other current assets		1,520		2,570
Total Current Assets		128,164		138,285
Utility Plant, at Original Cost
Natural gas		628,809		624,151
Less accumulated depreciation		168,104		165,966
Net Utility Plant in Service		460,705		458,185
Construction work in progress		1,274		2,375
Total Utility Plant		461,979		460,560
Other Property and Investments, Net		12,683		12,422
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes		13,672		21,725
Environmental remediation costs		2,314		2,522
Deferred purchase gas costs		389		14,922
Low income program		24,197		25,906
Pension and other postretirement benefits		77,207		65,937
Other		51,117		63,688
Total regulatory assets		168,896		194,700
Other assets
Goodwill		132,451		132,474
Other		5,994		6,110
Total other assets		138,445		138,584
Total Regulatory and Other Assets		307,341		333,284
Total Assets	$	910,167	$	944,551

2

The Southern Connecticut Gas Company
Balance Sheets (Unaudited)
	March 31,			December 31,
	2011			2010
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$	33,713		$	33,713
Notes payable		-			7,000
Accounts payable and accrued liabilities		12,440			14,275
Accounts payable,  natural gas purchased		29,786			29,165
Accounts payable to affiliates		346			1,047
Interest accrued		2,673			1,788
Taxes accrued		12,727			6,336
Other		10,102			11,863
Total Current Liabilities		101,787			105,187
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation		84,181			83,377
Deferred income taxes		10,233			22,282
Pension benefits		9,738			10,070
Other		28,711			21,342
Total regulatory liabilities		132,863			137,071
Other liabilities
Deferred income taxes		4,912			5,666
Pension and other postretirement benefits		55,443			61,332
Asset retirement obligation		10,942			10,803
Other		12,733			12,947
Total other liabilities		84,030			90,748
Total Regulatory and Other Liabilities		216,893			227,819
Long-term debt		189,722			190,751
Total Liabilities		508,402			523,757
Commitments
Common Stock Equity
Common stock		18,761			18,761
Capital in excess of par value		396,071			396,071
Retained (deficit) earnings		(13,375	)		5,806
Accumulated other comprehensive income		308			156
Total Common Stock Equity		401,765			420,794
Total Liabilities and Equity	$	910,167		$	944,551

3

The Southern Connecticut Gas Company
Statements of Cash Flows (Unaudited)
Three months ended March 31,	2011			2010
(Thousands)
Operating Activities
Net income	$	14,819		$	16,528
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and amortization		4,248			4,376
Amortization of regulatory and other assets and liabilities		(124	)		(371	)
Deferred  income taxes and investment tax credits deferred, net		(5,295	)		(3,465	)
Pension expense		1,468			1,030
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net		(25,648	)		(28,906	)
Inventories		24,471			28,003
Prepayments and other current assets		1,403			5,585
Accounts payable and accrued liabilities		(1,915	)		(3,009	)
Interest accrued		885			1,659
Taxes accrued		6,391			16,459
Other current liabilities		(1,761	)		(358	)
Other assets		24,266			19,580
Other liabilities		(7,414	)		(5,772	)
Net Cash Provided by Operating Activities		35,794			51,339
Investing Activities
Utility plant additions		(4,428	)		(3,017	)
Investments, net		(261	)		(204	)
Net Cash Used in Investing Activities		(4,689	)		(3,221	)
Financing Activities
Notes payable three months or less, net		(7,000	)		-
Dividends paid on common stock		(34,000	)		(14,000	)
Net Cash (Used in) Provided by  Financing Activities		(41,000	)		(14,000	)
Net Increase in Cash and Cash Equivalents		(9,895	)		34,118
Cash and Cash Equivalents, Beginning of Period		11,542			17,065
Cash and Cash Equivalents, End of Period	$	1,647		$	51,183

4

The Southern Connecticut Gas Company
Statement of Changes in Common Stock Equity (Unaudited)
(Thousands)
										Accumulated
	Common Stock									Other
	Outstanding $13.33 Par Value				Capital in		Retained			Comprehensive
	Shares		Amount		Excess of Par		Earnings (Deficit)			Income		Total
Balance, January 1, 2011		1,407	$	18,761	$	396,071	$	5,806		$	156	$	420,794
Net income								14,819					14,819
Other comprehensive income, net of tax											152		152
Comprehensive income													14,971
Dividends								(34,000	)				(34,000	)
Balance, March 31, 2011		1,407	$	18,761	$	396,071	$	(13,375	)	$	308	$	401,765

5

EX-99.8

	EXHIBIT 99.8
The Berkshire Gas Company
Financial Statements (Unaudited)
For the three months ended March 31, 2011

Table of Contents
March 31, 2011 and 2010
Financial Statements (Unaudited)	Page(s)
Statements of Income	1
Balance Sheets	2-3
Statements of Cash Flows	4
Statements of Changes in Common Stock Equity	5

The Berkshire Gas Company
Statements of Income (Unaudited)
Three months ended March 31	2011			2010
(Thousands)
Operating Revenues
Sales and services	$	30,527		$	30,534
Operating Expenses
Natural gas purchased		15,541			17,278
Other operating expenses		3,460			2,953
Maintenance		304			214
Depreciation and amortization		1,914			1,795
Other taxes		670			638
Total Operating Expenses		21,889			22,878
Operating Income		8,638			7,656
Other (Income)		(252	)		(345	)
Other Deductions		11			10
Interest Charges, Net		829			859
Income before Income Taxes		8,050			7,132
Income Taxes		3,146			2,787
Net Income		4,904			4,345
Preferred Stock Dividends		1			2
Earnings Available for Common Stock		4,903			4,343

1

The Berkshire Gas Company
Balance Sheets
	March		December
	2011		2010
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$	9,734	$	5,993
Accounts receivable and unbilled revenues, net		13,026		9,989
Gas in storage at average cost		1,951		4,872
Materials and supplies at average cost		442		392
Deferred income taxes		909		909
Prepayments and other current assets		1,472		1,700
Total Current Assets		27,534		23,855
Utility Plant, at Original Cost
Natural gas		156,959		156,595
Less accumulated depreciation		51,177		50,211
Net Utility Plant in Service		105,782		106,384
Construction work in progress		151		100
Total Utility Plant		105,933		106,484
Other Property and Investments, Net		2,958		2,975
Regulatory and Other Assets
Debt premium		8,426		8,681
Environmental remediation costs		14,738		14,498
Pension benefits		17,238		17,445
Other		1,021		4,058
Total regulatory assets		41,423		44,682
Other assets
Goodwill		52,476		52,476
Long term accumulated deferred income taxes		-		3,127
Other		1,287		1,193
Total other assets		53,763		56,796
Total Regulatory and Other Assets		95,186		101,478
Total Assets	$	231,611	$	234,792

2

The Berkshire Gas Company
Balance Sheets
	March		December
	2011		2010
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$	5,418	$	5,418
Accounts payable and accrued liabilities		3,604		4,356
Interest accrued		472		877
Taxes accrued		5,455		3,425
Environmental reserve		760		760
Derivative liability current		12		15
Other		2,379		3,930
Total Current Liabilities		18,100		18,781
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes		6,189		7,479
Unfunded future income taxes		158		163
Pension benefits		2,427		2,622
Accrued removal obligation		23,450		23,007
Total regulatory liabilities		32,224		33,271
Other Liabilities
Deferred income taxes		14,472		17,533
Environmental remediation costs		8,070		8,070
Postretirement reserves		5,068		5,110
Other		3,056		3,061
Total other liabilities		30,666		33,774
Total Regulatory and Other Liabilities		62,890		67,045
Long-term debt		40,008		40,263
Total Liabilities		120,998		126,089
Commitments and Contingencies
Preferred Stock
Preferred Stock		78		78
Common Stock Equity
Capital in excess of par value		106,046		106,046
Retained earnings		4,489		2,586
Accumulated  other comprehensive loss		-		(7	)
Total Common Stock Equity		110,535		108,625
Total Liabilities and Stockholders' Equity	$	231,611	$	234,792

3

The Berkshire Gas Company
Statements of Cash Flows (Unaudited)
Three months ended March 31	2011			2010
(Thousands)
Operating Activities
Net income	$	4,904		$	4,345
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation		1,614			1,555
Amortization of regulatory assets and liabilities		300			240
Deferred income taxes and investment tax credits, net		(1,235	)		(1,043	)
Pension income		170			65
Changes in current operating assets and liabilities
Accounts and other receivables		(3,037	)		(2,971	)
Inventories		2,870			3,093
Prepayments and other current assets		66			(30	)
Accounts payable and accrued liabilities		(752	)		(1,934	)
Taxes accrued		2,030			4,620
Interest Accrued		(406	)		(378	)
Other current liabilities		(1,554	)		(2,823	)
Other assets		2,106			1,792
Other liabilities		(249	)		1,475
Net Cash Provided by Operating Activities		6,827			8,006
Investing Activities
Utility plant additions		(51	)		(274	)
Contributions in aid of construction		10			(12	)
Other property and investments, net		(44	)		(80	)
Net Cash Used in Investing Activities		(85	)		(366	)
Financing Activities
Notes payable repayments		-			(5,700	)
Dividends on preferred stock		(1	)		(2	)
Dividends on common stock		(3,000	)		-
Net Cash Used in Financing Activities		(3,001	)		(5,702	)
Net Increase  in Cash and Cash Equivalents		3,741			1,938
Cash and Cash Equivalents, Beginning of Year		5,993			370
Cash and Cash Equivalents, End of Period		9,734			2,308

4

The Berkshire Gas Company
Statements of Changes in Common Stock Equity (Unaudited)
	Common Stock									Accumulated
	Outstanding				Capital in					Other			Total
	$2.50 Par Value				Excess of		Retained			Comprehensive			Common
(In Thousands, except number of shares and par value amounts)	Shares		Amount		Par Value		Earnings			Income (Loss)			Equity
Balance at December 31, 2010		100	$	250	$	106,046	$	2,586		$	(7	)	$	108,625
Net income								4,904						4,904
Other comprehensive income, net of tax											7			7
Comprehensive income														4,911
Dividends on common equity								(3,000	)					(3,000	)
Dividends on preferred stock								(1	)					(1	)
Balance at March 31, 2011		100	$	250	$	106,046	$	4,489			-		$	110,535

5