UIL (UIL) 10-Q 4 Nov 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document and Entity Information [Abstract]	'	'
Entity Registrant Name	'UIL HOLDINGS CORP	'
Entity Central Index Key	'0001082510	'
Current Fiscal Year End Date	'--12-31	'
Entity Well-known Seasoned Issuer	'Yes	'
Entity Voluntary Filers	'No	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	56,546,266
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-14	'

CONSOLIDATED_STATEMENT_OF_INCO

CONSOLIDATED STATEMENT OF INCOME (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
CONSOLIDATED STATEMENT OF INCOME (Unaudited) [Abstract]	'	'	'	'
Operating Revenues	$293,026	$316,478	$1,198,982	$1,183,591
Operation	'	'	'	'
Purchased power	37,962	37,314	123,771	105,996
Natural gas purchased	30,814	37,343	322,296	315,520
Operation and maintenance	95,251	89,810	290,828	273,539
Transmission wholesale	25,802	28,659	65,777	65,994
Depreciation and amortization (Note F)	35,578	50,761	112,408	146,537
Taxes - other than income taxes (Note F)	32,897	32,389	102,974	96,335
Rate case disallowances	0	17,543	0	17,543
Acquisition-related expenses (Note A)	570	0	6,090	0
Total Operating Expenses	258,874	293,819	1,024,144	1,021,464
Operating Income	34,152	22,659	174,838	162,127
Other Income and (Deductions), net	'	'	'	'
Acquisition-related bridge facility fees (Note A)	-849	0	-15,188	0
Other income and (deductions) (Note F)	4,336	5,153	12,822	15,718
Total Other Income and (Deductions), net	3,487	5,153	-2,366	15,718
Interest Charges, net	'	'	'	'
Interest on long-term debt	22,386	21,896	67,286	65,272
Other interest, net	636	-106	1,203	2,442
Interest charges, gross	23,022	21,790	68,489	67,714
Amortization of debt expense and redemption premiums	619	609	1,833	1,819
Total Interest Charges, net	23,641	22,399	70,322	69,533
Income from Equity Investments	3,492	3,930	10,398	11,590
Income Before Income Taxes	17,490	9,343	112,548	119,902
Income Taxes (Note E)	4,986	4,186	35,276	45,004
Net Income	12,504	5,157	77,272	74,898
Less: Preferred Stock Dividends of Subsidiary, Noncontrolling Interests	6	13	-21	39
Net Income attributable to UIL Holdings	$12,498	$5,144	$77,293	$74,859
Average Number of Common Shares Outstanding - Basic (in shares)	56,855	50,989	56,827	50,956
Average Number of Common Shares Outstanding - Diluted (in shares)	57,133	51,231	57,114	51,237
Earnings Per Share of Common Stock - Basic (Note A) (in dollars per share)	$0.22	$0.10	$1.36	$1.47
Earnings Per Share of Common Stock - Diluted (Note A) (in dollars per share)	$0.22	$0.10	$1.35	$1.46
Cash Dividends Declared per share of Common Stock (in dollars per share)	$0.43	$0.43	$1.30	$1.30

CONSOLIDATED_STATEMENT_OF_COMP

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Unaudited) [Abstract]	'	'	'	'
Net Income	$12,504	$5,157	$77,272	$74,898
Other Comprehensive Income (Loss), net of deferred income taxes [Abstract]	'	'	'	'
Changes in unrealized gains (losses) related to pension and other post-retirement benefit plans	-104	247	126	481
Other	-6	3	3	-25
Total Other Comprehensive Income (Loss), net of deferred income taxes	-110	250	129	456
Comprehensive Income	12,394	5,407	77,401	75,354
Less:	'	'	'	'
Preferred Stock Dividends of Subsidiary, Noncontrolling Interests	6	13	-21	39
Comprehensive Income Attributable to UIL Holdings	$12,388	$5,394	$77,422	$75,315

CONSOLIDATED_BALANCE_SHEET_Una

CONSOLIDATED BALANCE SHEET (Unaudited) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets	'	'
Unrestricted cash and temporary cash investments	$102,801	$69,153
Restricted cash	1,651	2,046
Accounts receivable less allowance of $10,481 and $11,545, respectively	212,379	245,252
Unbilled revenues	55,194	93,050
Current regulatory assets (Note A)	69,721	332,391
Natural gas in storage, at average cost	91,306	79,917
Deferred income taxes	0	21,742
Refundable taxes	13,870	8,244
Current portion of derivative assets (Note A)	6,861	9,098
Prepayments	23,437	14,989
Other	10,564	12,122
Total Current Assets	587,784	888,004
Other investments	'	'
Equity investment in GenConn (Note A)	114,305	118,241
Other	25,333	26,348
Total Other investments	139,638	144,589
Net Property, Plant and Equipment (Note A)	3,185,386	3,068,680
Regulatory Assets (Note A)	621,605	703,739
Deferred Charges and Other Assets	'	'
Unamortized debt issuance expenses	13,994	15,518
Derivative assets (Note A)	21,945	44,349
Goodwill	266,205	266,205
Other	21,184	13,136
Total Deferred Charges and Other Assets	323,328	339,208
Total Assets	4,857,741	5,144,220
Current Liabilities	'	'
Line of credit borrowings	10,000	0
Current portion of long-term debt	6,526	11,834
Accounts payable	111,484	164,416
Dividends payable	24,361	24,392
Accrued liabilities	91,458	78,125
Current regulatory liabilities (Note A)	30,043	261,729
Taxes accrued	17,633	23,490
Deferred income taxes	17,271	0
Interest accrued	25,714	21,933
Current portion of derivative liabilities (Note A)	23,404	26,904
Total Current Liabilities	357,894	612,823
Deferred Income Taxes	569,301	540,542
Regulatory Liabilities (Note A)	513,722	445,092
Other Noncurrent Liabilities	'	'
Pension accrued	157,934	170,853
Other post-retirement benefits accrued	79,016	78,539
Derivative liabilities (Note A)	59,948	169,327
Other	46,733	49,047
Total Other Noncurrent Liabilities	343,631	467,766
Commitments and Contingencies (Note J)	'	'
Capitalization (Note B)	'	'
Long-term debt, net of unamortized discount and premium	1,713,986	1,723,842
Preferred Stock, not subject to mandatory redemption	119	340
Common Stock Equity	'	'
Common stock	1,149,739	1,145,950
Paid-in capital	19,583	22,272
Retained earnings	189,102	185,058
Accumulated other comprehensive income (loss)	664	535
Net Common Stock Equity	1,359,088	1,353,815
Total Capitalization	3,073,193	3,077,997
Total Liabilities and Capitalization	$4,857,741	$5,144,220

CONSOLIDATED_BALANCE_SHEET_Una1

CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets	'	'
Allowance for doubtful accounts receivable	$10,481	$11,545

CONSOLIDATED_STATEMENT_OF_CASH

CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Cash Flows From Operating Activities	'	'
Net income	$77,272	$74,898
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation and amortization	114,241	148,356
Deferred income taxes	32,524	17,501
Allowance for funds used during construction (AFUDC) - equity	-6,869	-8,085
Stock-based compensation expense (Note A)	3,441	4,104
Pension expense	23,508	36,756
Undistributed (earnings) losses in equity investments	-9,801	-11,622
Rate case disallowances	0	17,543
Regulatory activity, net	83,021	35,176
Other non-cash items, net	995	2,156
Changes in:	'	'
Accounts receivable, net	31,737	36,930
Unbilled revenues	37,856	34,474
Natural gas in storage	-2,484	-4,023
Prepayments	-8,391	-13,615
Cash distributions from GenConn	10,404	7,704
Accounts payable	-38,298	-54,889
Interest accrued	3,781	1,962
Taxes accrued/refundable, net	-11,483	24,248
Accrued liabilities	11,080	-5,065
Accrued pension	-32,422	-69,963
Accrued other post-employment benefits	-3,528	-6,106
Other assets	469	-512
Other liabilities	6,500	-22
Total Adjustments	246,281	193,008
Net Cash provided by Operating Activities	323,553	267,906
Cash Flows from Investing Activities	'	'
Plant expenditures including AFUDC debt	-196,171	-224,172
Acquisition of Milford LNG	-20,110	0
Cash distributions from GenConn	3,927	2,063
Changes in restricted cash	395	918
Deposits in New England East West Solution (NEEWS) (Note C)	-5,068	-982
Other	690	350
Net Cash provided by (used in) Investing Activities	-216,337	-221,823
Cash Flows from Financing Activities	'	'
Issuance of common stock	0	72
Payments on long-term debt	-10,000	-20,000
Line of credit borrowings (repayments), net	10,000	40,000
Payment of common stock dividend	-73,280	-65,695
Other	-288	379
Net Cash provided by (used in) Financing Activities	-73,568	-45,244
Unrestricted Cash and Temporary Cash Investments:	'	'
Net change for the period	33,648	839
Balance at beginning of period	69,153	17,857
Balance at end of period	102,801	18,696
Non-cash investing activity:	'	'
Plant expenditures included in ending accounts payable	18,461	21,149
Plant expenditures funded by deposits in NEEWS	0	-18,469
Deposits in New England East West Solution (NEEWS)	$0	$18,469

BUSINESS_ORGANIZATION_AND_STAT

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2014
BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES [Abstract]	'
BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES	'
	(A)	BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES
	UIL Holdings is headquartered in New Haven, Connecticut, where its senior management maintains offices and is responsible for overall planning, operating and financial functions.  The primary business of UIL Holdings is ownership of its operating regulated utility businesses.  The utility businesses consist of the electric distribution and transmission operations of The United Illuminating Company (UI) and the natural gas transportation, distribution and sales operations of The Southern Connecticut Gas Company (SCG), Connecticut Natural Gas Corporation (CNG) and The Berkshire Gas Company (Berkshire, and together with SCG and CNG, the Gas Companies).
	UI is also a party to a joint venture with certain affiliates of NRG Energy, Inc. (NRG affiliates) pursuant to which UI holds 50% of the membership interests in GCE Holding LLC, whose wholly owned subsidiary, GenConn Energy LLC (collectively with GCE Holding LLC, GenConn) operates peaking generation plants in Devon, Connecticut (GenConn Devon) and Middletown, Connecticut (GenConn Middletown).
	Basis of Presentation
	The financial statements of UIL Holdings are prepared on a consolidated basis and therefore include the accounts of UIL Holdings’ majority-owned subsidiaries noted above.  Intercompany accounts and transactions have been eliminated in consolidation.  The year‑end balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America (GAAP).  Certain information and footnote disclosures, which are normally included in financial statements prepared in accordance with GAAP, have been condensed or omitted in accordance with Securities and Exchange Commission (SEC) rules and regulations.  We believe that the disclosures made are adequate to make the information presented not misleading.  The information presented in the Consolidated Financial Statements reflects all adjustments which, in our opinion, are necessary for a fair statement of the financial position and results of operations for the interim periods described herein.  All such adjustments are of a normal and recurring nature.  The results for the three- and nine-month periods ended September 30, 2014 are not necessarily indicative of the results for the entire fiscal year ending December 31, 2014.
	Certain immaterial amounts that were reported in the Consolidated Financial Statements in previous periods have been reclassified to conform to the current presentation.
	Philadelphia Gas Works
	On March 2, 2014, we entered into an asset purchase agreement with the City of Philadelphia (Asset Purchase Agreement) pursuant to which UIL Holdings, through a wholly-owned subsidiary, will acquire the operating assets and assume certain liabilities of Philadelphia Gas Works (PGW) for an initial purchase price of $1.86 billion, subject to adjustment (the Acquisition).
	The Acquisition is subject to the satisfaction or waiver of certain customary and other closing conditions for transactions of this type, including approvals from the Philadelphia City Council (City Council) and the Pennsylvania Public Utility Commission.  The Asset Purchase Agreement also contains termination provisions, including the right by either UIL Holdings or the City of Philadelphia to terminate the Asset Purchase Agreement if the Acquisition has not been consummated prior to March 31, 2015, subject to certain extension rights.  Since July 16, 2014, we have had the right to terminate the Asset Purchase Agreement pursuant to its terms because the City Council has not enacted an ordinance approving the Acquisition.  On October 27, 2014, the City Council announced that it would not endorse the sale of PGW.  In light of the City Council’s announcement, we are in the process of determining whether to exercise this contractual right and what future actions, if any, will be taken.   Without future action by either party, the Asset Purchase Agreement provides that it will terminate automatically on December 31, 2014.
	As of September 30, 2014, UIL Holdings incurred pre-tax acquisition-related expenses of approximately $21.3 million, $6.1 million of which represents legal, investment banking, and due diligence costs that are included in operating expenses and $15.2 million of which are fees associated with a Bridge Term Loan Agreement (Bridge Facility) that is included in other income and (deductions) in the Consolidated Statement of Income.  See Note (D) “Short-Term Credit Arrangements” for additional information about the Bridge Facility.
	Milford LNG Purchase
	On July 31, 2014, United Resources, Inc., a wholly owned subsidiary of UIL Holdings, purchased from Iberdrola USA, Inc. and certain of its subsidiaries, all of the outstanding equity of certain entities (the Purchased Entities) owning (a) a 14.6 million gallon liquefied natural gas (LNG) storage tank operated by SCG and located on property owned by SCG in Milford, Connecticut (the Tank), (b) certain equipment, materials and supplies used in or useful for the operation of the Tank (together with the Tank, the Assets) and (c) the LNG inventory for a cash purchase price of approximately $20.2 million.  The structure and the pricing of the transaction are intended to maintain the current regulatory structure of the Purchased Entities and the Assets, and have no impact on customers.  The Assets earn a rate of return equal to SCG’s allowed rate of return.
	Derivatives
	Our regulated subsidiaries are parties to contracts, and involved in transactions, that are derivatives.  The fair values of the gross derivative assets and liabilities as of September 30, 2014 and December 31, 2013 were as follows:
			September 30,			December 31,
			2014			2013
			(In Thousands)
	Gross derivative assets:
	Current Assets		$	6,861		$	9,098
	Deferred Charges and Other Assets		$	21,945		$	44,349
	Gross derivative liabilities:
	Current Liabilities		$	23,404		$	26,976
	Noncurrent Liabilities		$	59,948		$	169,327
	Contracts for Differences (CfDs)
	Pursuant to Connecticut’s 2005 Energy Independence Act, the Connecticut Public Utilities Regulatory Authority (PURA) solicited 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 the selected capacity resources and Connecticut electric customers, and provide the commitment necessary for owners of these resources to obtain necessary financing, PURA required that UI and The Connecticut Light and Power Company (CL&P) execute long-term contracts with the selected resources.  In August 2007, PURA 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.  UI executed two of the contracts and CL&P executed the other two contracts.  The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers.
	PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, 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 “Derivatives and Hedging.”  For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above.  As of September 30, 2014, UI has recorded a gross derivative asset of $28.8 million ($6.7 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $61.2 million, a gross derivative liability of $83.4 million ($55.7 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $6.6 million  See Note (K) “Fair Value of Financial Instruments” for additional CfD information.
	The unrealized (gains) and losses from fair value adjustments to these derivatives recorded in regulatory assets or regulatory liabilities for the three- and nine-month periods ended September 30, 2014 and 2013 were as follows:
			Three Months Ended						Nine Months Ended
			September 30,						September 30,
			2014			2013			2014			2013
			(In Thousands)						(In Thousands)
	Regulatory Assets - Derivative liabilities		$	393		$	(5,585	)	$	(81,623	)	$	(28,849	)
	Regulatory Liabilities - Derivative assets		$	5,077		$	-		$	(6,616	)	$	-
	The fluctuations in unrealized gains in the three- and nine-month periods ended September 30, 2014 compared to September 30, 2013 are primarily due to increases in forward prices for capacity and reserves as a result of ISO New England market rule changes.
	Weather Insurance Contracts
	On an annual basis, SCG and Berkshire each assess the need for weather insurance contracts for the upcoming heating season in order to provide financial protection from significant weather fluctuations.  According to the terms of such contracts, if temperatures are warmer than normal at a prescribed level for the contract period, a payment is received by the gas company; in addition, under certain of the contracts, if temperatures are colder than normal at a prescribed level for the contract period, the gas company is required to make a payment.  The premiums paid are amortized over the terms of the contracts.  The intrinsic value of the contracts is carried on the balance sheet with changes in value recorded in the income statement as Other Income and (Deductions).  As a result of PURA’s approval of a decoupling mechanism for CNG which went into effect in January 2014, CNG does not enter into weather insurance contracts.
	In September 2014, SCG and Berkshire entered into weather insurance contracts for the winter period of November 1, 2014 through April 30, 2015.  If temperatures are warmer than normal, SCG and Berkshire will receive payments up to a maximum of $3 million and $1 million, respectively.
	In October 2013, Berkshire entered into a weather insurance contract for the winter period of November 1, 2013 through April 30, 2014.  During the contract period, temperatures were colder than normal and Berkshire made a payment of $0.2 million upon expiration of the contract.
	In September 2013, SCG entered into a weather insurance contract for the winter period of November 1, 2013 through April 30, 2014.  During the contract period, temperatures were colder than normal and SCG made a payment of $2 million upon expiration of the contract.
	Earnings per Share
	The following table presents a reconciliation of the basic and diluted earnings per share calculations for the three- and nine‑month periods ended September 30, 2014 and 2013:
			Three Months Ended September 30,						Nine Months Ended September 30,
			2014			2013			2014			2013
			(In Thousands, except per share amounts)
	Numerator:
	Net income attributable to UIL Holdings		$	12,498		$	5,144		$	77,293		$	74,859
	Less:  Net income allocated to unvested units			7			5			45			83
	Net income attributable to common shareholders		$	12,491		$	5,139		$	77,248		$	74,776
	Denominator:
	Basic average number of shares outstanding			56,855			50,989			56,827			50,956
	Effect of dilutive securities (1)			278			242			287			281
	Diluted average number of shares outstanding			57,133			51,231			57,114			51,237
	Earnings per share:
	Basic		$	0.22		$	0.1		$	1.36		$	1.47
	Diluted		$	0.22		$	0.1		$	1.35		$	1.46
		-1	Includes unvested restricted stock and performance shares.
	Equity Investments
	UI is party to a 50-50 joint venture with NRG affiliates in GenConn, which operates two peaking generation plants in Connecticut.  UI’s investment in GenConn is being accounted for as an equity investment, the carrying value of which was $114.3 million and $118.2 million as of September 30, 2014 and December 31, 2013, respectively.  As of September 30, 2014, there was approximately $0.1 million of undistributed earnings from UI’s equity investment in GenConn.
	UI’s pre-tax income from its equity investment in GenConn was $3.5 million and $3.9 million for the three‑month periods ended September 30, 2014 and 2013, respectively.  UI’s pre-tax income from its equity investment in GenConn was $10.4 million and $11.6 million for the nine-month periods ending September 30, 2014 and 2013, respectively.
	Cash distributions from GenConn are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the Consolidated Statement of Cash Flows, respectively.  UI received cash distributions from GenConn of $5.5 million during the three-month period ended September 30, 2014.  Due to timing, UI did not receive any cash distributions from GenConn during the three‑month period ended September 30, 2013.  During the nine-month periods ending September 30, 2014 and 2013, UI received cash distributions from GenConn of approximately $14.3 million and $9.8 million, respectively.
	Regulatory Accounting
	Unless otherwise stated below, all of our regulatory assets earn a return.  Our regulatory assets and liabilities as of September 30, 2014 and December 31, 2013 included the following:
		Remaining		September 30,			December 31,
Period		2014		2013
			(In Thousands)
Regulatory Assets:
Nuclear plant investments – above market	(a)		$	-		$	238,868
Unamortized redemption costs	7 to 19 years			10,700			11,301
Pension and other post-retirement benefit plans	(b)			311,033			316,076
Environmental remediation costs	6 years			14,757			14,953
Hardship programs	(c)			27,119			25,019
Debt premium	1 to 24 years			28,763			34,178
Deferred purchased gas	(d)			-			2,556
Income taxes due principally to book-tax differences	(m)			155,191			149,015
Deferred income taxes	(e)			46,734			32,517
Contracts for differences	(f)			61,163			142,743
Excess generation service charge	(g)			-			6,909
Deferred transmission expense	(h)			3,272			9,615
Storm Costs	(i)			-			14,752
Other	(j)			32,594			37,628
Total regulatory assets				691,326			1,036,130
Less current portion of regulatory assets				69,721			332,391
Regulatory Assets, Net			$	621,605		$	703,739
Regulatory Liabilities:
Accumulated deferred investment tax credits	29 years		$	4,355		$	4,465
Income taxes due principally to book-tax differences	(m)			-			200,673
Deferred gain on sale of property	(a)			-			37,933
Excess generation service charge	(g)			25,296			-
Middletown/Norwalk local transmission network service collections	35 years			20,972			21,402
Pension and other post-retirement benefit plans	6 years			24,465			27,686
Asset retirement obligation	(k)			6,604			5,593
Low income programs	(l)			30,158			25,300
Asset removal costs	(j)			333,712			319,530
Deferred income taxes	(e)			26,247			43,421
Contracts for differences	(f)			6,608			-
Deferred purchased gas	(d)			6,596			-
Non-firm margin sharing credits	10 years			29,339			-
Other	(j)			29,413			20,818
Total regulatory liabilities				543,765			706,821
Less current portion of regulatory liabilities				30,043			261,729
Regulatory Liabilities, Net			$	513,722		$	445,092
(a) Asset/Liability relates to the Competitive Transition Assessment (CTA).  Balances are fully offset by amounts primarily included in income taxes, due principally to book-tax differences.  Total CTA costs recovery and stranded cost amortization are complete.  As a result of the outcome of UI’s 2013 distribution rate request, PURA approved UI’s proposed rate treatment to leave CTA rates unchanged until January 1, 2014 at which point the charge ended.  The remaining balances were eliminated.  See Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Other Proceedings” for additional information.
(b) Life is dependent upon timing of final pension plan distribution; balance, which is fully offset by a corresponding asset/liability, is recalculated each year in accordance with ASC 715 "Compensation-Retirement Benefits." See Note (G) “Pension and Other Benefits” for additional information.
(c) Hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.
(d) Deferred purchase gas costs balances at the end of the rate year are normally recorded/returned in the next year.
(e) The balance will be extinguished when the asset, which is fully offset by a corresponding liability, or liability has been realized or settled, respectively.
(f) Asset life is equal to delivery term of related contracts (which vary from approximately 6 - 13 years); balance fluctuates based upon quarterly market analysis performed on the related derivatives (Note K); amount, which does not earn a return, is fully offset by corresponding derivative asset/liability.  See “-Contracts for Differences” discussion above for additional information.
(g) Regulatory asset or liability which defers generation-related and nonbypassable federally mandated congestion costs or revenues for future recovery from or return to customers.  Amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
(h) Regulatory asset or liability which defers transmission income or expense and fluctuates based upon actual revenues and revenue requirements.
(i) Storm costs include accumulated costs for major storms occurring from January 2009 forward. See Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Rates” for a discussion of the recovery of these costs.
(j) Amortization period and/or balance vary depending on the nature, cost of removal and/or remaining life of the underlying assets/liabilities; asset amount includes decoupling ($5.5 million) and certain other amounts that are not currently earning a return. See Note (C) “Regulatory Proceedings for a discussion of the decoupling recovery period.
(k) The liability will be extinguished simultaneous with the retirement of the assets and settlement of the corresponding asset retirement obligation.
(l) Various hardship and payment plan programs approved for recovery.
(m) Amortization period and/or balance vary depending on the nature and/or remaining life of the underlying assets/liabilities; balances contain regulatory liabilities related to the CTA as well as regulatory assets not related to the CTA.  Due to the end of the CTA charge, the CTA regulatory liabilities are classified as current regulatory liabilities as of December 31, 2013 and the regulatory assets not related to the CTA are reclassified as long-term regulatory assets.
Stock-Based Compensation
Pursuant to the UIL Holdings 2008 Stock and Incentive Compensation Plan (2008 Stock Plan), target amounts of 123,940, 2,430, and 2,340 performance shares were granted to certain members of management in March 2014, May 2014 and August 2014; the averages of the high and low market prices on the grant dates, which approximate fair value, were $35.87 per share, $36.23 per share, and $34.90 per share respectively.
Also in March 2014, we granted a total of 2,196 shares of restricted stock to our President and Chief Executive Officer 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, which approximates fair value, was $35.87 per share.  Such shares vest in equal annual installments over a five-year period.
In May 2014, UIL Holdings granted a total of 25,160 shares of restricted stock to non-employee directors under the 2008 Stock Plan; the average of the high and low market price on the date of grant, which approximates fair value, was $35.90 per share.  Such shares vest in May 2015.
In June 2014, 9,540 shares of previously-granted performance shares and 2,177 shares of previously-granted restricted stock were forfeited.
Total stock-based compensation expense for the three-month periods ended September 30, 2014 and 2013 was an immaterial amount and $1.1 million, respectively.  Total stock-based compensation expense for the nine-month periods ended September 30, 2014 and 2013 was $3.4 million and $4.1 million, respectively.
Variable Interest Entities
We have identified GenConn as a variable interest entity (VIE), which is accounted for under the equity method.  UIL Holdings is not the primary beneficiary of GenConn, as defined in ASC 810 “Consolidation,” because it shares control of all significant activities of GenConn with its joint venturer, NRG affiliates.  As such, GenConn is not subject to consolidation.  GenConn recovers its costs through CfDs, which are cost of service-based and have been approved by PURA.  As a result, with the achievement of commercial operation by GenConn Devon and GenConn Middletown, our exposure to loss is primarily related to the potential for unrecovered GenConn operating or capital costs in a regulatory proceeding, the effect of which would be reflected in the carrying value of our 50% ownership position in GenConn and through “Income from Equity Investments” in UIL Holdings’ Consolidated Financial Statements.  Such exposure to loss cannot be determined at this time.  For further discussion of GenConn, see “–Equity Investments” as well as Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Equity Investment in Peaking Generation.”
We have identified the selected capacity resources with which UI has CfDs as VIEs and have concluded that UI is not the primary beneficiary as UI does not have the power to direct any of the significant activities of these capacity resources.   As such, we have not consolidated the selected capacity resources.  UI’s maximum exposure to loss through these agreements is limited to the settlement amount under the CfDs as described in “–Derivatives – Contracts for Differences (CfDs)” above; however any such losses are fully recoverable through electric rates.  UI has no requirement to absorb additional losses nor has UI provided any financial or other support during the periods presented that were not previously contractually required.
We have identified the entities for which UI is required to enter into long-term contracts to purchase Renewable Energy Credits (RECs) as VIEs.  In assessing these contracts for VIE identification and reporting purposes, we have aggregated the contracts based on similar risk characteristics and significance to UI.  UI is not the primary beneficiary as UI does not have the power to direct any of the significant activities of these entities.  UI’s exposure to loss is primarily related to the purchase and resale of the RECs, but, any losses incurred are recoverable through electric rates.  For further discussion of RECs, see Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – New Renewable Source Generation.”
New Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, which supersedes the revenue recognition requirements in ASC 605, Revenue Recognition.  ASU 2014-09 requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services.  ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2016 and is to be applied retrospectively.  We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated financial statements.
In June 2014, the FASB issued updated guidance to ASC 718 “Compensation – Stock Compensation” which prescribes the accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period.  This guidance is effective during interim and annual periods beginning after December 15, 2015 and can be applied on a prospective basis to all awards granted or modified after the effective date or retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter.  This guidance is not expected to have a material impact on UIL Holdings’ consolidated financial statements.

CAPITALIZATION

CAPITALIZATION	9 Months Ended
	Sep. 30, 2014
CAPITALIZATION [Abstract]	'
CAPITALIZATION	'
	(B)	CAPITALIZATION
	Common Stock
	UIL Holdings had 56,546,266 shares of its common stock, no par value, outstanding at September 30, 2014.
	Long‑Term Debt
	In August 2014, CNG repaid, upon maturity, all of its outstanding 8.12% Medium Term Notes, Series B, totaling $5 million.  Also in August 2014, CNG redeemed all of its outstanding 8.49% Medium Term Notes, Series B, totaling $5 million.
	Preferred Stock of Subsidiaries, Noncontrolling Interests
	The preferred stock of subsidiaries is a noncontrolling interest because it contains a feature that allows the holders to elect a majority of the subsidiary’s board of directors if preferred stock dividends are in default in an amount equivalent to four full quarterly dividends.  Such a potential redemption-triggering event is not solely within the control of the subsidiary.
	CNG has authorized 884,315 shares of its 8.00% non-callable cumulative preferred stock with a par value of $3.125 per share.  As of September 30, 2014, there were 108,706 shares issued and outstanding with a value of approximately $0.3 million, including 70,699 shares that were acquired by CNG’s parent, CTG Resources, Inc. on June 5, 2014, at a purchase price of $10.25 per share, or an aggregate amount of $0.7 million, pursuant to a tender offer.

REGULATORY_PROCEEDINGS

REGULATORY PROCEEDINGS	9 Months Ended
	Sep. 30, 2014
REGULATORY PROCEEDINGS [Abstract]	'
REGULATORY PROCEEDINGS	'
	(C)  REGULATORY PROCEEDINGS
	Electric Distribution and Transmission
	Rates
	On February 15, 2013, UI filed an application to amend its existing distribution rate schedules for two rate years.  On August 14, 2013, PURA issued a decision (the August Decision) which became effective on that date and which, among other things, increased the UI distribution and CTA allowed return on equity (ROE) from 8.75% to 9.15%, continued UI’s existing earnings sharing mechanism by which UI and customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism, and approved the establishment of the requested storm reserve.  Additionally, the August Decision disallowed approximately $22 million related to deferred storm costs and capital costs related to UI’s recently constructed administrative and operations buildings.  As a result of these disallowances and other adjustments related to the rate proceeding, we recorded a one-time pre-tax write off of $17.5 million related to UI in the third quarter of 2013.
	On December 16, 2013, PURA issued a final decision on UI’s Petition for Reconsideration of the August Decision.  The final decision on the reconsideration restored approximately $6.8 million of deferred storm costs and approximately $2.7 million of capital costs related to UI’s recently constructed administrative and operations buildings which had been disallowed in the August Decision.  As a result, we recorded a one-time pre-tax adjustment of approximately $9.2 million in the fourth quarter of 2013 to reverse such amounts written off in the third quarter of 2013 as a result of the August Decision.  The resulting storm regulatory asset allowed for recovery totaled approximately $45 million.  As a result of PURA’s final decision in UI’s final CTA reconciliation proceeding, the remaining storm regulatory asset was offset against the remaining CTA and Connecticut Yankee DOE litigation regulatory liabilities.  See Note “–Electric Distribution and Transmission – Other Proceedings” for additional information.
	Power Supply Arrangements
	UI has wholesale power supply agreements in place for its entire standard service load for all of 2014, for 70% of its standard service load for the first half of 2015 and 30% for the second half of 2015.  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.”  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 were to fall below investment grade.  If UI’s credit rating were to decline one rating at Standard & Poor’s or two ratings at Moody’s 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 at Standard & Poor’s and three ratings at Moody’s to fall below investment grade.  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 an event had occurred as of September 30, 2014 UI would have had to post an aggregate of approximately $9.7 million in collateral.
	New Renewable Source Generation
	Under Connecticut Public Act No. 11-80, “An Act Concerning the Establishment of the Department of Energy and Environmental Protection and Planning for Connecticut's Energy Future” (PA 11-80), Connecticut electric utilities are required to enter into long-term contracts to purchase Renewable Energy Credits (RECs) from renewable generators located on customer premises.  Under this program, UI is required to enter into contracts totaling approximately $200 million in commitments over an approximate 21-year period.  The obligations will phase in over a six-year solicitation period, and are expected to peak at an annual commitment level of about $13.6 million per year after all selected projects are online.  Upon purchase, UI accounts for the RECs as inventory.  UI expects to partially mitigate the cost of these contracts through the resale of the RECs.  PA 11-80 provides that the remaining costs (and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable from (or credited to) customers through electric rates.
	On October 23, 2013, PURA approved UI’s renewable connections program filed in accordance with PA 11-80, through which UI would develop up to 10 MW of renewable generation.  UI’s proposed budget of $35.0 million to develop the initial 7.8 MW has been approved by PURA.  The costs for this program would be recovered on a cost of service basis.  In its approval, PURA established a base ROE to be calculated as the greater of:  (A) the current UI authorized distribution ROE plus 25 basis points and (B) the current authorized distribution ROE for CL&P, less target equivalent market revenues (reflected as 25 basis points).  In addition, UI will retain a percentage of the market revenues from the project, which percentage is expected to equate to approximately 25 basis points on a levelized basis over the life of the project.
	Section 6 of Connecticut Public Act 13-303, “An Act Concerning Connecticut’s Clean Energy Goals,” (PA 13-303), authorized DEEP to direct Connecticut’s electric distribution companies, including UI, to enter into contracts for energy and/or RECs from Class I renewable resources in a quantity of up to 4% of the electric distribution companies’ distribution load.  On July 8, 2013, DEEP issued a request for proposals (RFP), and directed UI and CL&P to enter into power purchase agreements with the winning bidders.  On September 19, 2013, UI entered into contracts with two of the winning bidders, totaling approximately 3.5% of UI’s distribution load, which were subsequently approved by PURA.  Costs of each of these agreements will be fully recoverable through electric rates.  On December 18, 2013, Allco Finance Limited, an unsuccessful bidder in the RFP, filed a complaint against DEEP in the United States District Court in Connecticut alleging that DEEP’s direction to UI and CL&P to enter into the contracts violated the Supremacy Clause of the U.S. Constitution and the Federal Power Act by setting wholesale electricity rates.  UI is not a party to the litigation.
	Section 8 of PA 13-303 authorized DEEP to direct Connecticut’s electric distribution companies, including UI, to enter into contracts for energy and/or RECs from biomass, landfill gas and small hydro projects that qualify as Connecticut Class I renewable resources in a quantity up to 4% of the electric distribution companies’ distribution load.  At the direction of DEEP, in January 2014, UI entered into three contracts for the purchase of RECs associated with an aggregate of 5.7 MW of energy production from biomass plants in New England, which were subsequently approved by PURA.  PA 13‑303 provides that costs of any such agreements will be fully recoverable through electric rates.
	Transmission
	PURA decisions do not affect the revenue requirements determination for transmission, including the applicable return on equity (ROE), which are within the jurisdiction of the FERC.  For 2014, UI is estimating an overall allowed weighted-average ROE for its transmission business in the range of 12.0% to 12.2%.  This range includes the impact of the FERC order issued on October 16, 2014 and excludes any impacts of the reserve adjustment, both of which are discussed below.
	In September 2011, several New England governmental entities, including PURA, the Connecticut Attorney General and the Connecticut Office of Consumer Counsel, filed a joint complaint (Initial Complaint) with the FERC against ISO-NE and several New England transmission owners, including UI, claiming that the current approved base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by the New England transmission owners  of 11.14% is not just and reasonable and seeking a proposed reduction of the base ROE to 9.20% to be effective October 1, 2011.  A refund period of October 1, 2011 through December 31, 2012 (refund period) was established.
	On August 6, 2013, the presiding Administrative Law Judge issued an initial decision finding that the existing base ROE was unjust and unreasonable, and that the just and reasonable base ROE is 10.6% for the refund period and 9.7% for the period after a final opinion is issued by the FERC, prior to any adjustments that may be applied by the FERC in a final order based on the change in 10-year U.S. Treasury Bond rates from the date hearings closed to the date of the FERC’s order.  We recorded a reserve for the refund period related to the Initial Complaint of $2.6 million pre-tax during the third quarter of 2013 based upon our assessment of the ultimate outcome of the proceeding.
	In December 2012, various additional parties filed a complaint with the FERC against several New England transmission owners, including UI, seeking a proposed reduction of the base ROE to 8.70%, effective December 27, 2012 (Second Complaint).
	On June 19, 2014, FERC issued an order (June Order) in the Initial Complaint, tentatively finding that the just and reasonable base ROE for the New England transmission owners’ tariff is 10.57%.  In the June Order, FERC adopted a new method for determining cost of equity, changing from a one-step discounted cash flow (DCF) methodology to a two-step DCF, which includes a long-term growth component.  FERC also discontinued its past practice of adjusting the ROE to reflect changes in U.S. Treasury bond yields from the date of closing of the evidentiary record to the date of FERC decision.  In addition, FERC determined that it was inappropriate for the Administrative Law Judge to establish two separate ROEs, ordering that the final ROE, once determined, would apply to the refund period and prospectively.
	The June Order applied the two-step DCF methodology, using an assumed long-term growth rate based on the Gross Domestic Product, to tentatively find that the zone of reasonableness for the New England transmission owners is 7.03% to 11.74%.  Within that tentative zone of reasonableness, FERC found that, taking into account the unusual capital market conditions, the just and reasonable base ROE for the New England transmission owners’ tariff should be set halfway between the midpoint of the zone of reasonableness and the top of the zone of reasonableness, which, based on the record thus far in the proceeding, is 10.57%.   In connection with the application of the two-step DCF method, FERC established a paper hearing process following which FERC confirmed in its order on October 16, 2014 (October Order) that the Gross Domestic Product was the appropriate long-term growth rate to be used when calculating the base ROE.  Also in the October Order, the FERC set the New England transmission owners base ROE at 10.57% with a total or maximum ROE including incentives not to exceed 11.74%, for both the refund period and going forward effective on October 16, 2014.
	Also on June 19, 2014, FERC announced it would institute hearing and settlement judge procedures in the Second Complaint.   FERC determined there would be a 15-month refund period beginning December 27, 2012.  If settlement procedures are unsuccessful and this complaint is litigated, a final FERC order would likely be issued in 2016.  On October 21, 2014, the Settlement Judge recommended termination of settlement proceedings as the parties had indicated that they are at an impasse.
	On July 21, 2014, the New England transmission owners filed a request for clarification or rehearing, and the state complainants and others filed a request for rehearing, of various issues in the FERC order on the Initial Complaint, and the New England transmission owners filed a request for clarification or rehearing of the order on the Second Complaint.
	On July 31, 2014, complainants in the Initial Complaint and the Second Complaint filed an additional complaint (Third Complaint) with the FERC against the New England transmission owners, alleging that the current base ROE of 11.14% is not just and reasonable, and that under the new FERC two-step DCF methodology, the base ROE should be set at 8.84% or no more than 9.44%, the midpoint of the zone of reasonableness calculated by their consultant.  The Third Complaint argues that the FERC should not follow its June 19, 2014 Order setting the ROE at halfway between the midpoint and the top of the zone of reasonableness because financial market conditions are not anomalous.  The complainants have requested a 15-month refund period beginning July 31, 2014, and also ask for a determination that the top of the zone of reasonableness caps the ROE for each individual project.
	During the third quarter, we updated our assessment based upon the most recent information available.  Although we cannot predict the outcome of the proceedings involving the Second and Third Complaints, we have recorded reserves relating to potential refunds to customers, recording an additional pre-tax reserve of $5.3 million during the third quarter of 2014.
	New England East-West Solution
	Pursuant to an agreement with CL&P (the Agreement), UI has 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 located in Connecticut:  (1) the Greater Springfield Reliability Project (GSRP), which was fully energized in November 2013, (2) the Interstate Reliability Project (IRP), which is expected to be placed in service in late 2015 and (3) the Central Connecticut Reliability Project (CCRP), which is being reassessed as part of the Greater Hartford Central Connecticut Study (GHCC). As CL&P places assets in service, it will transfer title to certain NEEWS transmission assets to UI in proportion to UI’s investments, but CL&P will continue to maintain these portions of the transmission system pursuant to an operating and maintenance agreement (O&M Agreement) with UI.  Any termination of the Agreement pursuant to its terms would have no effect on the assets previously transferred to UI.
	Under the terms of the Agreement, UI has the option to make quarterly deposits to CL&P in exchange for ownership of specific NEEWS 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 originally proposed Connecticut portions of the NEEWS projects.  Based upon the current projected costs, UI’s investment rights in GSRP and IRP would be approximately $45 million.  In July 2014, ISO-NE presented the preferred GHCC transmission solutions to its Planning Advisory Committee.   UI is awaiting the final ISO-NE GHCC transmission solution report, expected in the fourth quarter of 2014, to determine the impact on UI’s aggregate investment in NEEWS.
	Deposits associated with NEEWS are recorded as assets at the time the deposit is made and they are reported in the ‘Other’ line item within the Deferred Charges and Other Assets section of the consolidated balance sheet.   When title to the assets is transferred to UI, the amount of the corresponding deposit is reclassified from other assets to plant-in-service on the balance sheet and shown as a non-cash investing activity in the consolidated statement of cash flows.
	As of September 30, 2014, UI had made aggregate deposits of $40.2 million under the Agreement since its inception, with assets valued at approximately $24.6 million having been transferred to UI, as follows:  In September 2012, CL&P transferred approximately $6.2 million of transmission assets associated with the GSRP, and in February 2013, CL&P transferred approximately $18.4 million of transmission assets, representing the remaining portion of the GSRP.  UI earned pre-tax income on deposits, net of transferred assets, of approximately $0.5 million and $0.3 million in the three-month periods ended September 30, 2014 and 2013, respectively.  UI earned pre-tax income on deposits, net of transferred assets, of approximately $1.2 million in each of the nine-month periods ended September 30, 2014 and 2013.
	Equity Investment in Peaking Generation
	UI is party to a 50-50 joint venture with NRG affiliates in GenConn, which operates two peaking generation plants in Connecticut.  The two peaking generation plants, GenConn Devon and GenConn Middletown, are both participating in the ISO-New England markets.  PURA has approved revenue requirements for the period from January 1, 2014 through December 31, 2014 of $30.8 million and $37.5 million for GenConn Devon and GenConn Middletown, respectively.  In addition, PURA has ruled that GenConn project costs incurred that were in excess of the proposed costs originally submitted in 2008 were prudently incurred and are recoverable.  Such costs are included in the determination of the 2014 approved revenue requirements.
	GenConn filed a revenue requirements request with PURA on June 25, 2014, seeking approval of its 2015 revenue requirements for the period commencing January 1, 2015 for both the GenConn Devon and GenConn Middletown facilities.  A final decision on this request is expected by the end of 2014.
	Other Proceedings
	On October 2, 2014, PURA issued a draft decision in a docket addressing UI’s semi-annual Generation Service Charge (GSC), bypassable federally mandated congestion charge and the nonbypassable federally mandated congestion charge reconciliations.  PURA’s draft decision, for which UI has filed written exceptions and will present oral arguments, if adopted without change as the final decision, would allow for recovery of $8.3 million of the $11.3 million request included in UI’s filing for the reconciliation of certain revenues and expenses relating to the period from 2004 through 2013 and result in UI recording a pre-tax write-off of approximately $3.1 million during the fourth quarter of 2014.
	On October 20, 2014, PURA issued a draft decision in UI’s final CTA reconciliation proceeding. Based upon our assessment, we believe that it is probable that the final decision will result in the extinguishment of all remaining CTA balances and, as such, we have eliminated the CTA balances as of September 30, 2014. In addition, the draft decision allowed for the application of an approximate $8.2 million remaining CTA regulatory liability as well as an approximate $12.0 million regulatory liability related to the Connecticut Yankee DOE litigation against the storm regulatory asset balance.   The remaining regulatory liability balance was applied to the GSC “working capital allowance” and will be returned to customers through the nonbypassable federally mandated congestion charge.
	Gas Distribution
	Rates
	The allowed returns on equity established by PURA are 9.18% and 9.36% for CNG and SCG, respectively.  Berkshire’s rates are established by the DPU.  Berkshire’s 10-year rate plan, which was approved by the DPU and included an approved ROE of 10.5%, expired on January 31, 2012.  Berkshire continues to charge the rates that were in effect at the end of the rate plan.  In response to a letter from the DPU requesting that Berkshire notify the DPU when Berkshire expected to file its next base distribution rate case and the test year for the filing, Berkshire responded that calendar year 2014 would be the earliest test year for a base rate case, and with such a test year a case would be filed by approximately May 15, 2015 with rates to be effective April 1, 2016.
	On July 8, 2013, CNG filed an application to amend its existing base delivery rate.  On January 22, 2014, PURA issued a final decision, with an effective date of January 10, 2014, which, among other things, approved an allowed ROE of 9.18%, a decoupling mechanism, and two separate ratemaking mechanisms that reconcile actual revenue requirements related to CNG’s cast iron and bare steel replacement program and system expansion.  Additionally, the final decision requires the establishment of an earnings sharing mechanism by which CNG and customers share on a 50/50 basis all earnings above the allowed ROE in a calendar year.  The decision also allows CNG, on a provisional basis, to reflect the increased rate base resulting from the accumulated deferred income tax (ADIT) impacts of the election of Section 338(h)(10) of the Internal Revenue Code upon its acquisition by UIL Holdings.   The decision requires CNG to seek a private letter ruling from the Internal Revenue Service with regard to the specific question of whether, after extinguishment of an ADIT balance, a directive by a public utility commission to institute a ratemaking mechanism to reflect a credit to ratepayers of ADIT benefits lost through a Section 338(h)(10) election would result in a normalization violation.  The decision states that in the event of a ruling from the Internal Revenue Service stating that imposing such a ratemaking mechanism would not create a normalization violation, PURA would adjust rates to offset the ratemaking impacts of the 338(h)(10) election on rate base.  We estimate the impact to be an approximate $2.5 to $3.5 million decrease in annual revenue requirements.  In March 2014, CNG filed a draft of its private letter ruling request with PURA for approval.  During the first quarter of 2014, the Office of Consumer Counsel (OCC) appealed the decision to the Connecticut Superior Court with regard to the establishment of an adjustment mechanism for incremental cast iron and bare steel replacement as well as PURA’s directive to seek a private letter ruling with respect to the extinguishment of ADITs rather than ordering a rate credit to hold customers harmless from the ratemaking effect of extinguishing the ADITs.  At the request of PURA, the OCC and CNG have entered into settlement discussions regarding the appeal and CNG requested from PURA, and was granted, an extension of time for submitting the private letter ruling request to the Internal Revenue Service.

SHORTTERM_CREDIT_ARRANGEMENTS

SHORT-TERM CREDIT ARRANGEMENTS	9 Months Ended
	Sep. 30, 2014
SHORT-TERM CREDIT ARRANGEMENTS [Abstract]	'
SHORT-TERM CREDIT ARRANGEMENTS	'
	(D)	SHORT‑TERM CREDIT ARRANGEMENTS
	As of September 30, 2014, there was $10 million in borrowings outstanding under the existing revolving credit agreement among UIL Holdings, certain of its subsidiaries and a group of banks, that expires on November 30, 2016 (the UIL Holdings Credit Facility).  Under the UIL Holdings Credit Facility, UIL Holdings has outstanding standby letters of credit in the aggregate amount of $4.4 million, which expire on January 31, 2015 and June 16, 2015.  Available credit under the UIL Holdings Credit Facility at September 30, 2014 totaled $385.6 million for UIL Holdings and its subsidiaries in the aggregate.  We record borrowings under the UIL Holdings Credit Facility as short‑term debt, but the UIL Holdings Credit Facility provides for longer term commitments from banks allowing us to borrow and reborrow funds, at our option, until the facility’s expiration, thus affording us flexibility in managing its working capital requirements.
	In connection with the Acquisition, on March 17, 2014, UIL Holdings and certain of its subsidiaries entered into an Amendment No. 1 to the UIL Holdings Credit Facility.  The purpose of the Amendment No. 1 was to address provisions that would be impacted by the Acquisition, including (i) amending the lien provisions to allow the existence of liens related to the Acquisition, (ii) amending the debt restrictions to allow UIL Holdings  to incur debt of up to $1.6 billion, subject to conditions and (iii) amending the debt covenant provisions to allow UIL Holdings and certain of its subsidiaries to maintain a ratio of Consolidated Debt to Consolidated Capital of not greater than 0.77 to 1.00, in connection with the Acquisition, subject to conditions.
	On March 28, 2014, in connection with the Acquisition, UIL Holdings and its subsidiary, WGP Acquisition LLC (WGP), entered into a 364-day Bridge Term Loan Agreement (Bridge Facility) with a group of banks and Morgan Stanley Senior Funding, Inc., as administrative agent in an aggregate principal amount of up to $1.9 billion.  Under the Bridge Facility, UIL Holdings may borrow the full amount and WGP may borrow up to $950 million, subject to the aggregate limit of $1.9 billion.  UIL Holdings and WGP will be severally liable for their respective borrowings.  Any undrawn commitments under the Bridge Facility will automatically be terminated on the date of the closing of the Acquisition.  As of September 30, 2014, there were no amounts outstanding under the Bridge Facility.

INCOME_TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2014
INCOME TAXES [Abstract]	'
INCOME TAXES	'
	(E)	INCOME TAXES
	Differences in the treatment of certain transactions for book and tax purposes cause UIL Holdings’ overall effective tax rate to differ from the statutory tax rate.  In accordance with ASC 740, we use an estimated annual effective tax rate approach to calculate interim period income tax expense for ordinary income.   We also record separate income tax effects for significant unusual or infrequent items such as the Acquisition.
	Consolidated income tax expense decreased $9.7 million for the first nine months of 2014, as compared to the first nine months of 2013 due primarily to a lower annualized effective tax rate and the Acquisition.  The annualized effective tax rate decreased from 37.9% for the nine months ended September 30, 2013 to 32.9% for the nine months ended September 30, 2014 due primarily to the absence in 2014 of non-normalized CTA amortization as well as favorable changes in state flow through depreciation.

SUPPLEMENTARY_INFORMATION

SUPPLEMENTARY INFORMATION	9 Months Ended
	Sep. 30, 2014
SUPPLEMENTARY INFORMATION [Abstract]	'
SUPPLEMENTARY INFORMATION	'
	(F)	SUPPLEMENTARY INFORMATION
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2014		2013		2014			2013
			(In Thousands)				(In Thousands)
	Depreciation and Amortization
	Property, plant, and equipment depreciation		$	32,860	$	30,870	$	97,208		$	89,788
	Amortization of regulatory assets			2,718		19,891		15,200			56,749
	Total Depreciation and Amortization		$	35,578	$	50,761	$	112,408		$	146,537
	Taxes - Other than Income Taxes
	Operating:
	Connecticut gross earnings		$	16,199	$	17,780	$	54,671		$	54,873
	Local real estate and personal property			13,310		12,417		37,399			34,416
	Payroll taxes			3,046		2,069		9,877			6,584
	Other			342		123		1,027			462
	Total Taxes - Other than Income Taxes		$	32,897	$	32,389	$	102,974		$	96,335
	Other Income and (Deductions)
	Interest income		$	666	$	243	$	1,731		$	1,449
	Allowance for funds used during construction - equity			1,949		2,751		6,869			8,085
	Allowance for funds used during construction - debt			1,201		1,533		4,032			5,869
	Weather insurance			-		-		(2,437	)		-
	Other			520		626		2,627			315
	Total Other Income and (Deductions)		$	4,336	$	5,153	$	12,822		$	15,718

PENSION_AND_OTHER_BENEFITS

PENSION AND OTHER BENEFITS	9 Months Ended
	Sep. 30, 2014
PENSION AND OTHER BENEFITS [Abstract]	'
PENSION AND OTHER BENEFITS	'
	(G)	PENSION AND OTHER BENEFITS
	During the nine months ended September 30, 2014, we made pension contributions of $23.0 million.  No further contributions are expected during the remainder of 2014.
	The following tables represent the components of net periodic benefit cost for pension and other postretirement benefits as well as the actuarial weighted-average assumptions used in calculating net periodic benefit cost for the three- and nine‑month periods ended September 30, 2014 and 2013:
			Three Months Ended September 30,
			Pension Benefits						Other Postretirement Benefits
			2014			2013			2014			2013
			(In Thousands)
	Components of net periodic benefit cost:
	Service cost		$	2,896		$	3,696		$	404		$	481
	Interest cost			11,019			9,988			1,487			1,384
	Expected return on plan assets			(13,560	)		(12,863	)		(700	)		(648	)
	Amortization of:
	Prior service costs			73			151			71			(13	)
	Actuarial loss			3,097			5,208			(172	)		444
	Settlements (1)			-			632			-			-
	Net periodic benefit cost		$	3,525		$	6,812		$	1,090		$	1,648
			Nine Months Ended September 30,
			Pension Benefits						Other Postretirement Benefits
			2014			2013			2014			2013
			(In Thousands)
	Components of net periodic benefit cost:
	Service cost		$	8,688		$	11,088		$	1,212		$	1,443
	Interest cost			33,057			29,964			4,461			4,152
	Expected return on plan assets			(40,680	)		(38,589	)		(2,100	)		(1,944	)
	Amortization of:
	Prior service costs			219			453			213			(39	)
	Actuarial loss			9,291			15,624			(516	)		1,332
	Settlements (1)			-			632			-			-
	Net periodic benefit cost		$	10,575		$	19,172		$	3,270		$	4,944
			Three and Nine Months Ended September 30,
			Pension Benefits						Other Postretirement Benefits
				2014			2013			2014			2013
	Discount rate			4.90%-5.20	%		4.00%-4.25	%		4.85%-5.20	%		4.00%-4.25	%
	Average wage increase			3.50%-3.80	%		3.50%-3.80	%		N/A			N/A
	Return on plan assets			7.75%-8.00	%		7.75%-8.00	%		5.56%-8.00	%		5.56%-8.00	%
	Composite health care trend rate (current year)			N/A			N/A			7	%		7.5	%
	Composite health care trend rate (2018 forward)			N/A			N/A			5	%		5	%
	-1	Reflects settlement charges resulting from a distribution to a former employee upon retirement
	N/A – not applicable

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2014
RELATED PARTY TRANSACTIONS [Abstract]	'
RELATED PARTY TRANSACTIONS	'
	(H)  RELATED PARTY TRANSACTIONS
	A Director of UIL Holdings holds a beneficial interest in the building located at 157 Church Street, New Haven, Connecticut, where UIL Holdings leases office space.  UIL Holdings’ lease payments for this office space for each of the three‑month periods ended September 30, 2014 and 2013 totaled $0.4 million.  UIL Holdings’ lease payments for this office space for each of the nine-month periods ended September 30, 2014 and 2013 totaled $1.4 million and $1.1 million, respectively.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2014
COMMITMENTS AND CONTINGENCIES [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	(J)  COMMITMENTS AND CONTINGENCIES
	In the ordinary course of business, we are involved in various proceedings, including legal, tax, regulatory and environmental matters, which require management’s assessment to determine the probability of whether a loss will occur and, if probable, an estimate of probable loss.  When assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated, we accrue a reserve and disclose the reserve and related matter.  We disclose material matters when losses are probable but for which an estimate cannot be reasonably estimated or when losses are not probable but are reasonably possible.  Subsequent analysis is performed on a periodic basis to assess the impact of any changes in events or circumstances and any resulting need to adjust existing reserves or record additional reserves.  However, given the inherent unpredictability of these legal and regulatory proceedings, we cannot assure you that our assessment of such proceedings will reflect the ultimate outcome, and an adverse outcome in certain matters could have a material adverse effect on our results of operations or cash flows.
	Connecticut Yankee Atomic Power Company
	UI has a 9.5% stock ownership share in the Connecticut Yankee Atomic Power Company, an inactive nuclear generating company (Connecticut Yankee), the carrying value of which was $0.2 million as of September 30, 2014.  Connecticut Yankee has completed the physical decommissioning of its generation facilities and is now engaged primarily in the long-term storage of its spent nuclear fuel. Connecticut Yankee collects its costs through wholesale FERC-approved rates from UI and several other New England utilities.  UI recovers these costs from its customers through electric rates.
	On May 1, 2013, Connecticut Yankee filed an application with FERC to, among other things, reduce its rates and eliminate future decommissioning funding requirements for its owners, using the United States Department of Energy (DOE) damage award, discussed below.  On June 27, 2013, FERC issued a final decision which approved both the proposed rate reduction and the elimination of future decommissioning funding requirements.  As a result, UI’s obligation and corresponding regulatory asset were eliminated at that time.
	DOE Spent Fuel Litigation
	In 1998, Connecticut Yankee filed claims in the United States Court of Federal Claims seeking damages resulting from the breach of the 1983 spent fuel and high level waste disposal contract between Connecticut Yankee and the DOE.  In September 2010, the court issued its decision and awarded Connecticut Yankee damages of $39.7 million for its spent fuel-related costs through 2001, which was affirmed in May 2012.  Connecticut Yankee received payment of the damage award and, in light of its ownership share, in July 2013 UI received approximately $3.8 million of such award which was credited back to customers through the CTA.
	In December 2007, Connecticut Yankee filed a second set of complaints with the United States Court of Federal Claims against the DOE seeking damages incurred since January 1, 2002 for the DOE’s failure to remove Connecticut Yankee’s spent fuel.  In November 2013, the court issued a final judgment, which was not appealed, awarding Connecticut Yankee damages of $126.3 million.  In light of its ownership share, in June 2014, UI received approximately $12.0 million of such award which was applied, in part, against the remaining storm regulatory asset balance.  The remaining regulatory liability balance was applied to the GSC “working capital allowance” and will be returned to customers through the nonbypassable federally mandated congestion charge.  See Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Other Proceedings” for additional information.
	In August 2013, Connecticut Yankee filed a third set of complaints with the United States Court of Federal Claims against the DOE seeking unspecified damages incurred since January 1, 2009.
	Environmental Matters
	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, we may incur substantial capital expenditures for equipment modifications and additions, monitoring equipment and recording devices, as well as additional operating expenses.  The total amount of these expenditures is not now determinable.  Environmental damage claims may also arise from the operations of our subsidiaries.  Significant environmental issues known to us at this time are described below.
	Site Decontamination, Demolition and Remediation Costs
	In 2000, UI conveyed a former generation site on the Mill River in New Haven (English Station) 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, 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 English Station site into compliance with applicable environmental laws.  As of September 30, 2014, approximately $0.1 million of the escrow fund remained.  In 2006, QE sold the property to Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat).  In January 2012, Evergreen Power and Asnat filed a lawsuit in federal district court in Connecticut against UI seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigating and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site.  In May 2012, UI filed an answer and counterclaims.  In July 2012, Evergreen Power and Asnat filed a motion for partial summary judgment with respect to UI’s liability under the federal Comprehensive Environmental Response, Compensation, and Liability Act, which was denied without prejudice.  In December 2013, Evergreen and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the property; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages.  UI believes the claims are without merit.  UI’s knowledge of the current conditions at the English Station site is insufficient for it to make a reliable update of the original $1.9 million remediation estimate.  Management cannot presently assess the potential financial impact, if any, of the suits, and thus has not recorded a liability related to it and no amount of loss, if any, can be reasonably estimated at this time.
	On April 8, 2013, DEEP issued an administrative order addressed to UI, QE, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site.  Mediation of the matter began in the fourth quarter of 2013 and is on-going.  At this time, management cannot predict the financial impact on UI of the DEEP order or other matters relating to this site and no amount of loss, if any, can be reasonably estimated at this time.
	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.
	The Gas Companies own or have previously owned properties where Manufactured Gas Plants (MGPs) had historically operated.  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 federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations.  Each of the Gas Companies has or had an ownership interest in one of such properties contaminated as a result of MGP-related activities.  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; no liability was recorded in respect of these sites as of September 30, 2014 and no amount of loss, if any, can be reasonably estimated at this time.  In the past, the Gas Companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites.
	SCG owns properties on Housatonic Avenue in Bridgeport, and on Chapel Street in New Haven, and CNG owns a property located on Columbus Boulevard in Hartford, all of which are former MGP sites.  Costs associated with the remediation of the sites could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates.  We cannot presently reasonably estimate the costs or range of costs of remediation or the likelihood of recoverability.  As a result, as of September 30, 2014, we have not recorded any liabilities related to these properties.
	Berkshire owns property on Mill Street in Greenfield, Massachusetts, a former MGP site.  We estimate that expenses associated with the remaining remedial activities, as well as the required ongoing monitoring and reporting to the Massachusetts Department of Environmental Protection will amount to approximately $2.9 million and have recorded a liability and offsetting regulatory asset for such expenses as of September 30, 2014.  Historically, Berkshire has received approval from the DPU for recovery of environmental expenses in its customer rates.
	Berkshire formerly owned a site on East Street (the East Street Site) in Pittsfield, Massachusetts, a former MGP site.  The East Street Site is part of a larger site known as the GE–Pittsfield/Housatonic River Site.  Berkshire sold the East Street Site to the General Electric Company (GE) in the 1970s and was named a potentially responsible party for the site by the EPA in 1990.  In December 2002, Berkshire reached a settlement with GE which provides, among other things, a framework for Berkshire and GE to allocate various monitoring and remediation costs at the East Street Site.  As of September 30, 2014, we had accrued approximately $1.2 million and established a regulatory asset for these and future costs incurred by GE in responding to releases of hazardous substances at the East Street Site.  Historically, Berkshire has received approval from the DPU for recovery of remediation expenses in its customer rates.
	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 filed lawsuits in Connecticut state court on September 22, 2009, March 23, 2009 and January 25, 2010, respectively.  The claims, as revised by the general contractor in October 2011, sought payment for change order requests of approximately $33.3 million, a 10% general contractor mark-up on any approved subcontractor change order claims (approximately $2.3 million), interest, costs, and attorneys' fees.  In December 2011, UI settled claims brought by the two subcontractors and their respective lawsuits were dismissed with prejudice, reducing UI’s estimate of the general contractor’s claims to approximately $7.7 million, exclusive of the contractor’s claims for interest, costs, and attorneys’ fees.    UI also pursued an indemnification claim against the general contractor for the payments made in settlement to the two subcontractors.
	On September 3, 2013, a Memorandum of Decision was issued by the court finding for UI on all claims but one related to certain change orders, and ordering UI to pay the Contractor approximately $1.3 million.  The decision also found against UI on the indemnification claims.  On October 22, 2013, the general contractor filed an appeal of the Court’s ruling.  UI expects to recover any amounts paid to resolve the contractor and subcontractor claims through UI’s transmission revenue requirements.
	On April 30, 2013, an affiliate of the general contractor for the Middletown/Norwalk Transmission Project, purporting to act as a shareholder on behalf of UIL Holdings, filed a complaint against the UIL Holdings Board of Directors alleging that the directors breached a fiduciary duty by failing to undertake an independent investigation in response to a letter from the affiliate asking for an investigation regarding alleged improper practices by UI in connection with the Middletown/Norwalk Transmission Project.  On October 25, 2013, the court granted the defendants’ motion to dismiss the complaint. On November 15, 2013, the plaintiff filed an appeal of the court order in the Connecticut Appellate Court, which remains pending.

FAIR_VALUE_MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2014
FAIR VALUE MEASUREMENTS [Abstract]	'
FAIR VALUE MEASUREMENTS	'
	(K)	FAIR VALUE MEASUREMENTS
	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.  Our 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 the fair value of our financial assets and liabilities, other than pension benefits and other postretirement benefits, as of September 30, 2014 and December 31, 2013.
			Fair Value Measurements Using
			Quoted Prices in			Significant			Significant			Total
			Active Markets			Other			Unobservable
			for Identical			Observable			Inputs (Level 3)
			Assets (Level 1)			Inputs (Level 2)
	30-Sep-14		(In Thousands)
	Assets:
	Derivative assets		$	-		$	-		$	28,806		$	28,806
	Noncurrent investments			11,249			-			-			11,249
	Deferred Compensation Plan			3,502			-			-			3,502
	Supplemental retirement benefit trust life insurance policies			-			8,259			-			8,259
			$	14,751		$	8,259		$	28,806		$	51,816
	Liabilities:
	Derivative liabilities		$	-		$	-		$	83,352		$	83,352
	Long-term debt			-			1,915,475			-			1,915,475
			$	-		$	1,915,475		$	83,352		$	1,998,827
	Net fair value assets/(liabilities), September 30, 2014		$	14,751		$	(1,907,216	)	$	(54,546	)	$	(1,947,011	)
	31-Dec-13
	Assets:
	Derivative assets		$	-		$	-		$	53,447		$	53,447
	Noncurrent investments			11,148			-			-			11,148
	Deferred Compensation Plan			3,775			-			-			3,775
	Supplemental retirement benefit trust life insurance policies			-			7,898			-			7,898
			$	14,923		$	7,898		$	53,447		$	76,268
	Liabilities:
	Derivative liabilities		$	-		$	-		$	196,233		$	196,233
	Long-term debt			-			1,846,867			-			1,846,867
			$	-		$	1,846,867		$	196,233		$	2,043,100
	Net fair value assets/(liabilities), December 31, 2013		$	14,923		$	(1,838,969	)	$	(142,786	)	$	(1,966,832	)
	Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements.  The derivative assets consist primarily of CfDs.  The determination of fair value of the CfDs was based on a probability-based expected cash flow analysis that was discounted at the September 30, 2014 or December 31, 2013 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.  We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs.  Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs.  Additional quantitative information about Level 3 fair value measurements is as follows:
					Range at	Range at
			Unobservable Input		30-Sep-14	31-Dec-13
	Contracts for differences		Risk of non-performance		0.00% - 0.64%	0.00% - 0.62%
			Discount rate		1.78% - 2.64%	1.75% - 3.21%
			Forward pricing ($ per MW)		$3.15 - $14.59	$1.40 - $9.83
	Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs.
	The fair value of the noncurrent investments 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 mutual funds and UIL Holdings 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 based upon such pricing information.
	The determination of the fair value of the supplemental retirement benefit trust life insurance policies was based on quoted prices as of September 30, 2014 and December 31, 2013 in the active markets for the various funds within which the assets are held.
	Long-term debt is carried at cost on the consolidated balance sheet.  The fair value of long-term debt as displayed in the table above is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit 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 nine-month period ended September 30, 2014.
			Nine Months Ended
			30-Sep-14
			(In Thousands)
	Net derivative assets/(liabilities), December 31, 2013		$	(142,786	)
	Unrealized gains and (losses), net			88,240
	Net derivative assets/(liabilities), September 30, 2014		$	(54,546	)
	Change in unrealized gains (losses), net relating to net derivative assets/(liabilities), still held as of September 30, 2014		$	88,240
	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 CfDs for the nine-month period ended September 30, 2014.  The amounts offset the net CfDs liabilities included in the derivative liabilities detailed above.
			Nine Months Ended
			30-Sep-14
			(In Thousands)
	Net regulatory assets/(liabilities), December 31, 2013		$	142,786
	Unrealized (gains) and losses, net			(88,240	)
	Net regulatory assets/(liabilities), September 30, 2014		$	54,546

SEGMENT_INFORMATION

SEGMENT INFORMATION	9 Months Ended
	Sep. 30, 2014
SEGMENT INFORMATION [Abstract]	'
SEGMENT INFORMATION	'
	(M)	SEGMENT INFORMATION
	UIL Holdings is organized into Electric Distribution, Electric Transmission and Gas Distribution reporting segments based on several factors including, but not limited to, the nature of each segment’s products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates.  The following measures of segment profit and loss are utilized by management to make decisions about allocating resources to the segments and assessing performance.  The following table reconciles certain segment information with that provided in our Consolidated Financial Statements.  In the table, distribution includes all electric utility revenue and expenses except for transmission, which is provided in a separate column.  “Other” includes the information for the remainder of our non‑utility activities and unallocated corporate costs, including minority interest investments and administrative costs.  Revenues from inter‑segment transactions are not material.  All of our revenues are derived in the United States.
			Three months ended September 30, 2014
			Electric Distribution and Transmission
			Distribution		Transmission		Total		Gas Distribution			Other			Total
	Operating Revenues		$	134,289	$	62,926	$	197,215	$	94,708		$	1,103		$	293,026
	Purchased power and gas			37,962		-		37,962		30,504			310			68,776
	Operation and maintenance			42,819		11,456		54,275		44,950			(3,974	)		95,251
	Transmission wholesale			-		25,802		25,802		-			-			25,802
	Depreciation and amortization			11,943		4,208		16,151		16,477			2,950			35,578
	Taxes - other than income taxes			14,244		10,441		24,685		9,082			(870	)		32,897
	Acquisition-related expenses			-		-		-		-			570			570
	Operating Income			27,321		11,019		38,340		(6,305	)		2,117			34,152
	Other Income and (Deductions), net			2,877		881		3,758		702			(973	)		3,487
	Interest Charges, net			7,590		3,375		10,965		7,116			5,560			23,641
	Income from Equity Investments			3,492		-		3,492		-			-			3,492
	Income (Loss) Before Income Taxes			26,100		8,525		34,625		(12,719	)		(4,416	)		17,490
	Income Taxes			8,173		3,048		11,221		(6,229	)		(6	)		4,986
	Net Income (Loss)			17,927		5,477		23,404		(6,490	)		(4,410	)		12,504
	Less:
	Preferred Stock Dividends of
	Subsidiary, Noncontrolling Interests			-		-		-		6			-			6
	Net Income (Loss) attributable to UIL Holdings		$	17,927	$	5,477	$	23,404	$	(6,496	)	$	(4,410	)	$	12,498
	Total Capital Expenditures (1)		$	-	$	-	$	31,523	$	32,926		$	6,181		$	70,630
			Three months ended September 30, 2013
			Electric Distribution and Transmission
			Distribution		Transmission		Total		Gas Distribution			Other			Total
	Operating Revenues		$	151,369	$	67,830	$	219,199	$	97,244		$	35		$	316,478
	Purchased power and gas			37,314		-		37,314		37,343			-			74,657
	Operation and maintenance			43,387		11,532		54,919		36,271			(1,380	)		89,810
	Transmission wholesale			-		28,659		28,659		-			-			28,659
	Depreciation and amortization			28,397		4,152		32,549		17,202			1,010			50,761
	Taxes - other than income taxes			13,390		10,466		23,856		8,410			123			32,389
	Rate case disallowances			17,543		-		17,543		-			-			17,543
	Operating Income			11,338		13,021		24,359		(1,982	)		282			22,659
	Other Income and (Deductions), net			3,534		746		4,280		234			639			5,153
	Interest Charges, net			6,088		2,763		8,851		7,507			6,041			22,399
	Income from Equity Investments			3,930		-		3,930		-			-			3,930
	Income (Loss) Before Income Taxes			12,714		11,004		23,718		(9,255	)		(5,120	)		9,343
	Income Taxes			5,607		3,890		9,497		(2,970	)		(2,341	)		4,186
	Net Income (Loss)			7,107		7,114		14,221		(6,285	)		(2,779	)		5,157
	Less:
	Preferred Stock Dividends of
	Subsidiary, Noncontrolling Interests			-		-		-		13			-			13
	Net Income (Loss) attributable to UIL Holdings		$	7,107	$	7,114	$	14,221	$	(6,298	)	$	(2,779	)	$	5,144
	Total Capital Expenditures (1)		$	-	$	-	$	41,310	$	25,968		$	12,910		$	80,188
			Nine months ended September 30, 2014
			Electric Distribution and Transmission
			Distribution		Transmission		Total		Gas Distribution			Other			Total
	Operating Revenues		$	397,384	$	183,715	$	581,099	$	616,780		$	1,103		$	1,198,982
	Purchased power and gas			123,771		-		123,771		321,986			310			446,067
	Operation and maintenance			135,282		36,049		171,331		130,761			(11,264	)		290,828
	Transmission wholesale			-		65,777		65,777		-			-			65,777
	Depreciation and amortization			35,902		12,635		48,537		55,994			7,877			112,408
	Taxes - other than income taxes			38,597		26,832		65,429		37,080			465			102,974
	Acquisition-related expenses			-		-		-		-			6,090			6,090
	Operating Income			63,832		42,422		106,254		70,959			(2,375	)		174,838
	Other Income and (Deductions), net			9,503		2,793		12,296		(587	)		(14,075	)		(2,366	)
	Interest Charges, net			22,661		9,832		32,493		21,320			16,509			70,322
	Income from Equity Investments			10,398		-		10,398		-			-			10,398
	Income (Loss) Before Income Taxes			61,072		35,383		96,455		49,052			(32,959	)		112,548
	Income Taxes			18,015		12,262		30,277		18,749			(13,750	)		35,276
	Net Income (Loss)			43,057		23,121		66,178		30,303			(19,209	)		77,272
Less:
Preferred Stock Dividends of
Subsidiary, Noncontrolling Interests			-		-		-		(21	)		-			(21	)
Net Income (Loss) attributable to UIL Holdings		$	43,057	$	23,121	$	66,178	$	30,324		$	(19,209	)	$	77,293
Total Capital Expenditures (1)		$	-	$	-	$	91,600	$	78,278		$	26,293		$	196,171
		Nine months ended September 30, 2013
		Electric Distribution and Transmission
		Distribution		Transmission		Total		Gas Distribution			Other			Total
Operating Revenues		$	421,959	$	180,412	$	602,371	$	581,115		$	105		$	1,183,591
Purchased power and gas			105,996		-		105,996		315,520			-			421,516
Operation and maintenance			132,919		33,212		166,131		111,496			(4,088	)		273,539
Transmission wholesale			-		65,994		65,994		-			-			65,994
Depreciation and amortization			72,924		12,123		85,047		58,515			2,975			146,537
Taxes - other than income taxes			36,860		25,260		62,120		33,769			446			96,335
Rate case disallowances			17,543		-		17,543		-			-			17,543
Operating Income			55,717		43,823		99,540		61,815			772			162,127
Other Income and (Deductions), net			10,687		3,465		14,152		(298	)		1,864			15,718
Interest Charges, net			19,834		9,104		28,938		22,415			18,180			69,533
Income from Equity Investments			11,590		-		11,590		-			-			11,590
Income (Loss) Before Income Taxes			58,160		38,184		96,344		39,102			(15,544	)		119,902
Income Taxes			24,464		13,474		37,938		14,770			(7,704	)		45,004
Net Income (Loss)			33,696		24,710		58,406		24,332			(7,840	)		74,898
Less:
Preferred Stock Dividends of
Subsidiary, Noncontrolling Interests			-		-		-		39			-			39
Net Income (Loss) attributable to UIL Holdings		$	33,696	$	24,710	$	58,406	$	24,293		$	(7,840	)	$	74,859
Total Capital Expenditures (1)		$	-	$	-	$	124,437	$	63,771		$	35,964		$	224,172
		Electric Distribution and Transmission (2)
		Distribution		Transmission		Total		Gas Distribution (3)			Other			Total (3)
Total Assets at September 30, 2014		$	-	$	-	$	2,709,623	$	1,996,825		$	151,293		$	4,857,741
Total Assets at December 31, 2013		$	-	$	-	$	2,950,707	$	2,010,246		$	183,267		$	5,144,220
-1	Information for segmenting total capital expenditures between Distribution and Transmission is not available.  Total Electric Distribution and Transmission capital expenditures are disclosed in the Total Electric Distribution and Transmission column.
-2	Information for segmenting total assets between Distribution and Transmission is not available.  Total Electric Distribution and Transmission assets are disclosed in the Total Electric and Distribution and Transmission column.  Net plant in service is segregated by segment and, as of September 30, 2014, was $1,236.8 million and $658.2 million for Distribution and Transmission, respectively.  As of December 31, 2013, net plant in service was $1,181.1 million and $656.0 million for Distribution and Transmission, respectively.
-3	Includes $266.2 million of goodwill in the Gas Distribution segment as of September 30, 2014 and December 31, 2013.

BUSINESS_ORGANIZATION_AND_STAT1

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2014
BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES [Abstract]	'
Basis of Presentation	'
	Basis of Presentation
	The financial statements of UIL Holdings are prepared on a consolidated basis and therefore include the accounts of UIL Holdings’ majority-owned subsidiaries noted above.  Intercompany accounts and transactions have been eliminated in consolidation.  The year‑end balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America (GAAP).  Certain information and footnote disclosures, which are normally included in financial statements prepared in accordance with GAAP, have been condensed or omitted in accordance with Securities and Exchange Commission (SEC) rules and regulations.  We believe that the disclosures made are adequate to make the information presented not misleading.  The information presented in the Consolidated Financial Statements reflects all adjustments which, in our opinion, are necessary for a fair statement of the financial position and results of operations for the interim periods described herein.  All such adjustments are of a normal and recurring nature.  The results for the three- and nine-month periods ended September 30, 2014 are not necessarily indicative of the results for the entire fiscal year ending December 31, 2014.
	Certain immaterial amounts that were reported in the Consolidated Financial Statements in previous periods have been reclassified to conform to the current presentation.
Philadelphia Gas Works	'
	Philadelphia Gas Works
	On March 2, 2014, we entered into an asset purchase agreement with the City of Philadelphia (Asset Purchase Agreement) pursuant to which UIL Holdings, through a wholly-owned subsidiary, will acquire the operating assets and assume certain liabilities of Philadelphia Gas Works (PGW) for an initial purchase price of $1.86 billion, subject to adjustment (the Acquisition).
	The Acquisition is subject to the satisfaction or waiver of certain customary and other closing conditions for transactions of this type, including approvals from the Philadelphia City Council (City Council) and the Pennsylvania Public Utility Commission.  The Asset Purchase Agreement also contains termination provisions, including the right by either UIL Holdings or the City of Philadelphia to terminate the Asset Purchase Agreement if the Acquisition has not been consummated prior to March 31, 2015, subject to certain extension rights.  Since July 16, 2014, we have had the right to terminate the Asset Purchase Agreement pursuant to its terms because the City Council has not enacted an ordinance approving the Acquisition.  On October 27, 2014, the City Council announced that it would not endorse the sale of PGW.  In light of the City Council’s announcement, we are in the process of determining whether to exercise this contractual right and what future actions, if any, will be taken.   Without future action by either party, the Asset Purchase Agreement provides that it will terminate automatically on December 31, 2014.
	As of September 30, 2014, UIL Holdings incurred pre-tax acquisition-related expenses of approximately $21.3 million, $6.1 million of which represents legal, investment banking, and due diligence costs that are included in operating expenses and $15.2 million of which are fees associated with a Bridge Term Loan Agreement (Bridge Facility) that is included in other income and (deductions) in the Consolidated Statement of Income.  See Note (D) “Short-Term Credit Arrangements” for additional information about the Bridge Facility.
Milford LNG Purchase	'
	Milford LNG Purchase
	On July 31, 2014, United Resources, Inc., a wholly owned subsidiary of UIL Holdings, purchased from Iberdrola USA, Inc. and certain of its subsidiaries, all of the outstanding equity of certain entities (the Purchased Entities) owning (a) a 14.6 million gallon liquefied natural gas (LNG) storage tank operated by SCG and located on property owned by SCG in Milford, Connecticut (the Tank), (b) certain equipment, materials and supplies used in or useful for the operation of the Tank (together with the Tank, the Assets) and (c) the LNG inventory for a cash purchase price of approximately $20.2 million.  The structure and the pricing of the transaction are intended to maintain the current regulatory structure of the Purchased Entities and the Assets, and have no impact on customers.  The Assets earn a rate of return equal to SCG’s allowed rate of return.
Derivatives	'
	Derivatives
	Our regulated subsidiaries are parties to contracts, and involved in transactions, that are derivatives.  The fair values of the gross derivative assets and liabilities as of September 30, 2014 and December 31, 2013 were as follows:
			September 30,			December 31,
			2014			2013
			(In Thousands)
	Gross derivative assets:
	Current Assets		$	6,861		$	9,098
	Deferred Charges and Other Assets		$	21,945		$	44,349
	Gross derivative liabilities:
	Current Liabilities		$	23,404		$	26,976
	Noncurrent Liabilities		$	59,948		$	169,327
	Contracts for Differences (CfDs)
	Pursuant to Connecticut’s 2005 Energy Independence Act, the Connecticut Public Utilities Regulatory Authority (PURA) solicited 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 the selected capacity resources and Connecticut electric customers, and provide the commitment necessary for owners of these resources to obtain necessary financing, PURA required that UI and The Connecticut Light and Power Company (CL&P) execute long-term contracts with the selected resources.  In August 2007, PURA 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.  UI executed two of the contracts and CL&P executed the other two contracts.  The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers.
	PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, 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 “Derivatives and Hedging.”  For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above.  As of September 30, 2014, UI has recorded a gross derivative asset of $28.8 million ($6.7 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $61.2 million, a gross derivative liability of $83.4 million ($55.7 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $6.6 million  See Note (K) “Fair Value of Financial Instruments” for additional CfD information.
	The unrealized (gains) and losses from fair value adjustments to these derivatives recorded in regulatory assets or regulatory liabilities for the three- and nine-month periods ended September 30, 2014 and 2013 were as follows:
			Three Months Ended						Nine Months Ended
			September 30,						September 30,
			2014			2013			2014			2013
			(In Thousands)						(In Thousands)
	Regulatory Assets - Derivative liabilities		$	393		$	(5,585	)	$	(81,623	)	$	(28,849	)
	Regulatory Liabilities - Derivative assets		$	5,077		$	-		$	(6,616	)	$	-
	The fluctuations in unrealized gains in the three- and nine-month periods ended September 30, 2014 compared to September 30, 2013 are primarily due to increases in forward prices for capacity and reserves as a result of ISO New England market rule changes.
	Weather Insurance Contracts
	On an annual basis, SCG and Berkshire each assess the need for weather insurance contracts for the upcoming heating season in order to provide financial protection from significant weather fluctuations.  According to the terms of such contracts, if temperatures are warmer than normal at a prescribed level for the contract period, a payment is received by the gas company; in addition, under certain of the contracts, if temperatures are colder than normal at a prescribed level for the contract period, the gas company is required to make a payment.  The premiums paid are amortized over the terms of the contracts.  The intrinsic value of the contracts is carried on the balance sheet with changes in value recorded in the income statement as Other Income and (Deductions).  As a result of PURA’s approval of a decoupling mechanism for CNG which went into effect in January 2014, CNG does not enter into weather insurance contracts.
	In September 2014, SCG and Berkshire entered into weather insurance contracts for the winter period of November 1, 2014 through April 30, 2015.  If temperatures are warmer than normal, SCG and Berkshire will receive payments up to a maximum of $3 million and $1 million, respectively.
	In October 2013, Berkshire entered into a weather insurance contract for the winter period of November 1, 2013 through April 30, 2014.  During the contract period, temperatures were colder than normal and Berkshire made a payment of $0.2 million upon expiration of the contract.
	In September 2013, SCG entered into a weather insurance contract for the winter period of November 1, 2013 through April 30, 2014.  During the contract period, temperatures were colder than normal and SCG made a payment of $2 million upon expiration of the contract.
Earnings per Share	'
	Earnings per Share
	The following table presents a reconciliation of the basic and diluted earnings per share calculations for the three- and nine‑month periods ended September 30, 2014 and 2013:
			Three Months Ended September 30,						Nine Months Ended September 30,
			2014			2013			2014			2013
			(In Thousands, except per share amounts)
	Numerator:
	Net income attributable to UIL Holdings		$	12,498		$	5,144		$	77,293		$	74,859
	Less:  Net income allocated to unvested units			7			5			45			83
	Net income attributable to common shareholders		$	12,491		$	5,139		$	77,248		$	74,776
	Denominator:
	Basic average number of shares outstanding			56,855			50,989			56,827			50,956
	Effect of dilutive securities (1)			278			242			287			281
	Diluted average number of shares outstanding			57,133			51,231			57,114			51,237
	Earnings per share:
	Basic		$	0.22		$	0.1		$	1.36		$	1.47
	Diluted		$	0.22		$	0.1		$	1.35		$	1.46
		-1	Includes unvested restricted stock and performance shares.
Equity Investments	'
	Equity Investments
	UI is party to a 50-50 joint venture with NRG affiliates in GenConn, which operates two peaking generation plants in Connecticut.  UI’s investment in GenConn is being accounted for as an equity investment, the carrying value of which was $114.3 million and $118.2 million as of September 30, 2014 and December 31, 2013, respectively.  As of September 30, 2014, there was approximately $0.1 million of undistributed earnings from UI’s equity investment in GenConn.
	UI’s pre-tax income from its equity investment in GenConn was $3.5 million and $3.9 million for the three‑month periods ended September 30, 2014 and 2013, respectively.  UI’s pre-tax income from its equity investment in GenConn was $10.4 million and $11.6 million for the nine-month periods ending September 30, 2014 and 2013, respectively.
	Cash distributions from GenConn are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the Consolidated Statement of Cash Flows, respectively.  UI received cash distributions from GenConn of $5.5 million during the three-month period ended September 30, 2014.  Due to timing, UI did not receive any cash distributions from GenConn during the three‑month period ended September 30, 2013.  During the nine-month periods ending September 30, 2014 and 2013, UI received cash distributions from GenConn of approximately $14.3 million and $9.8 million, respectively.
Regulatory Accounting	'
	Regulatory Accounting
	Unless otherwise stated below, all of our regulatory assets earn a return.  Our regulatory assets and liabilities as of September 30, 2014 and December 31, 2013 included the following:
		Remaining		September 30,			December 31,
		Period		2014			2013
				(In Thousands)
	Regulatory Assets:
	Nuclear plant investments – above market	(a)		$	-		$	238,868
	Unamortized redemption costs	7 to 19 years			10,700			11,301
	Pension and other post-retirement benefit plans	(b)			311,033			316,076
	Environmental remediation costs	6 years			14,757			14,953
	Hardship programs	(c)			27,119			25,019
	Debt premium	1 to 24 years			28,763			34,178
	Deferred purchased gas	(d)			-			2,556
	Income taxes due principally to book-tax differences	(m)			155,191			149,015
	Deferred income taxes	(e)			46,734			32,517
	Contracts for differences	(f)			61,163			142,743
	Excess generation service charge	(g)			-			6,909
	Deferred transmission expense	(h)			3,272			9,615
	Storm Costs	(i)			-			14,752
	Other	(j)			32,594			37,628
	Total regulatory assets				691,326			1,036,130
	Less current portion of regulatory assets				69,721			332,391
	Regulatory Assets, Net			$	621,605		$	703,739
	Regulatory Liabilities:
	Accumulated deferred investment tax credits	29 years		$	4,355		$	4,465
	Income taxes due principally to book-tax differences	(m)			-			200,673
	Deferred gain on sale of property	(a)			-			37,933
	Excess generation service charge	(g)			25,296			-
	Middletown/Norwalk local transmission network service collections	35 years			20,972			21,402
	Pension and other post-retirement benefit plans	6 years			24,465			27,686
	Asset retirement obligation	(k)			6,604			5,593
	Low income programs	(l)			30,158			25,300
	Asset removal costs	(j)			333,712			319,530
	Deferred income taxes	(e)			26,247			43,421
	Contracts for differences	(f)			6,608			-
	Deferred purchased gas	(d)			6,596			-
	Non-firm margin sharing credits	10 years			29,339			-
	Other	(j)			29,413			20,818
	Total regulatory liabilities				543,765			706,821
	Less current portion of regulatory liabilities				30,043			261,729
	Regulatory Liabilities, Net			$	513,722		$	445,092
	(a) Asset/Liability relates to the Competitive Transition Assessment (CTA).  Balances are fully offset by amounts primarily included in income taxes, due principally to book-tax differences.  Total CTA costs recovery and stranded cost amortization are complete.  As a result of the outcome of UI’s 2013 distribution rate request, PURA approved UI’s proposed rate treatment to leave CTA rates unchanged until January 1, 2014 at which point the charge ended.  The remaining balances were eliminated.  See Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Other Proceedings” for additional information.
	(b) Life is dependent upon timing of final pension plan distribution; balance, which is fully offset by a corresponding asset/liability, is recalculated each year in accordance with ASC 715 "Compensation-Retirement Benefits." See Note (G) “Pension and Other Benefits” for additional information.
	(c) Hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.
	(d) Deferred purchase gas costs balances at the end of the rate year are normally recorded/returned in the next year.
	(e) The balance will be extinguished when the asset, which is fully offset by a corresponding liability, or liability has been realized or settled, respectively.
	(f) Asset life is equal to delivery term of related contracts (which vary from approximately 6 - 13 years); balance fluctuates based upon quarterly market analysis performed on the related derivatives (Note K); amount, which does not earn a return, is fully offset by corresponding derivative asset/liability.  See “-Contracts for Differences” discussion above for additional information.
	(g) Regulatory asset or liability which defers generation-related and nonbypassable federally mandated congestion costs or revenues for future recovery from or return to customers.  Amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
	(h) Regulatory asset or liability which defers transmission income or expense and fluctuates based upon actual revenues and revenue requirements.
	(i) Storm costs include accumulated costs for major storms occurring from January 2009 forward. See Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Rates” for a discussion of the recovery of these costs.
	(j) Amortization period and/or balance vary depending on the nature, cost of removal and/or remaining life of the underlying assets/liabilities; asset amount includes decoupling ($5.5 million) and certain other amounts that are not currently earning a return. See Note (C) “Regulatory Proceedings for a discussion of the decoupling recovery period.
	(k) The liability will be extinguished simultaneous with the retirement of the assets and settlement of the corresponding asset retirement obligation.
	(l) Various hardship and payment plan programs approved for recovery.
	(m) Amortization period and/or balance vary depending on the nature and/or remaining life of the underlying assets/liabilities; balances contain regulatory liabilities related to the CTA as well as regulatory assets not related to the CTA.  Due to the end of the CTA charge, the CTA regulatory liabilities are classified as current regulatory liabilities as of December 31, 2013 and the regulatory assets not related to the CTA are reclassified as long-term regulatory assets.
Stock-Based Compensation	'
	Stock-Based Compensation
	Pursuant to the UIL Holdings 2008 Stock and Incentive Compensation Plan (2008 Stock Plan), target amounts of 123,940, 2,430, and 2,340 performance shares were granted to certain members of management in March 2014, May 2014 and August 2014; the averages of the high and low market prices on the grant dates, which approximate fair value, were $35.87 per share, $36.23 per share, and $34.90 per share respectively.
	Also in March 2014, we granted a total of 2,196 shares of restricted stock to our President and Chief Executive Officer 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, which approximates fair value, was $35.87 per share.  Such shares vest in equal annual installments over a five-year period.
	In May 2014, UIL Holdings granted a total of 25,160 shares of restricted stock to non-employee directors under the 2008 Stock Plan; the average of the high and low market price on the date of grant, which approximates fair value, was $35.90 per share.  Such shares vest in May 2015.
	In June 2014, 9,540 shares of previously-granted performance shares and 2,177 shares of previously-granted restricted stock were forfeited.
	Total stock-based compensation expense for the three-month periods ended September 30, 2014 and 2013 was an immaterial amount and $1.1 million, respectively.  Total stock-based compensation expense for the nine-month periods ended September 30, 2014 and 2013 was $3.4 million and $4.1 million, respectively.
Variable Interest Entities	'
	Variable Interest Entities
	We have identified GenConn as a variable interest entity (VIE), which is accounted for under the equity method.  UIL Holdings is not the primary beneficiary of GenConn, as defined in ASC 810 “Consolidation,” because it shares control of all significant activities of GenConn with its joint venturer, NRG affiliates.  As such, GenConn is not subject to consolidation.  GenConn recovers its costs through CfDs, which are cost of service-based and have been approved by PURA.  As a result, with the achievement of commercial operation by GenConn Devon and GenConn Middletown, our exposure to loss is primarily related to the potential for unrecovered GenConn operating or capital costs in a regulatory proceeding, the effect of which would be reflected in the carrying value of our 50% ownership position in GenConn and through “Income from Equity Investments” in UIL Holdings’ Consolidated Financial Statements.  Such exposure to loss cannot be determined at this time.  For further discussion of GenConn, see “–Equity Investments” as well as Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Equity Investment in Peaking Generation.”
	We have identified the selected capacity resources with which UI has CfDs as VIEs and have concluded that UI is not the primary beneficiary as UI does not have the power to direct any of the significant activities of these capacity resources.   As such, we have not consolidated the selected capacity resources.  UI’s maximum exposure to loss through these agreements is limited to the settlement amount under the CfDs as described in “–Derivatives – Contracts for Differences (CfDs)” above; however any such losses are fully recoverable through electric rates.  UI has no requirement to absorb additional losses nor has UI provided any financial or other support during the periods presented that were not previously contractually required.
	We have identified the entities for which UI is required to enter into long-term contracts to purchase Renewable Energy Credits (RECs) as VIEs.  In assessing these contracts for VIE identification and reporting purposes, we have aggregated the contracts based on similar risk characteristics and significance to UI.  UI is not the primary beneficiary as UI does not have the power to direct any of the significant activities of these entities.  UI’s exposure to loss is primarily related to the purchase and resale of the RECs, but, any losses incurred are recoverable through electric rates.  For further discussion of RECs, see Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – New Renewable Source Generation.”
New Accounting Pronouncements	'
	New Accounting Pronouncements
	In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, which supersedes the revenue recognition requirements in ASC 605, Revenue Recognition.  ASU 2014-09 requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services.  ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2016 and is to be applied retrospectively.  We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated financial statements.
	In June 2014, the FASB issued updated guidance to ASC 718 “Compensation – Stock Compensation” which prescribes the accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period.  This guidance is effective during interim and annual periods beginning after December 15, 2015 and can be applied on a prospective basis to all awards granted or modified after the effective date or retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter.  This guidance is not expected to have a material impact on UIL Holdings’ consolidated financial statements.

BUSINESS_ORGANIZATION_AND_STAT2

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES (Tables)	9 Months Ended
	Sep. 30, 2014
BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES [Abstract]	'
Unrealized Gains and Losses From Mark-To-Market Adjustments	'
	The unrealized (gains) and losses from fair value adjustments to these derivatives recorded in regulatory assets or regulatory liabilities for the three- and nine-month periods ended September 30, 2014 and 2013 were as follows:
			Three Months Ended						Nine Months Ended
			September 30,						September 30,
			2014			2013			2014			2013
			(In Thousands)						(In Thousands)
	Regulatory Assets - Derivative liabilities		$	393		$	(5,585	)	$	(81,623	)	$	(28,849	)
	Regulatory Liabilities - Derivative assets		$	5,077		$	-		$	(6,616	)	$	-
Reconciliation of Basic and Diluted Earnings Per Share	'
	The following table presents a reconciliation of the basic and diluted earnings per share calculations for the three- and nine‑month periods ended September 30, 2014 and 2013:
			Three Months Ended September 30,						Nine Months Ended September 30,
			2014			2013			2014			2013
			(In Thousands, except per share amounts)
	Numerator:
	Net income attributable to UIL Holdings		$	12,498		$	5,144		$	77,293		$	74,859
	Less:  Net income allocated to unvested units			7			5			45			83
	Net income attributable to common shareholders		$	12,491		$	5,139		$	77,248		$	74,776
	Denominator:
	Basic average number of shares outstanding			56,855			50,989			56,827			50,956
	Effect of dilutive securities (1)			278			242			287			281
	Diluted average number of shares outstanding			57,133			51,231			57,114			51,237
	Earnings per share:
	Basic		$	0.22		$	0.1		$	1.36		$	1.47
	Diluted		$	0.22		$	0.1		$	1.35		$	1.46
		-1	Includes unvested restricted stock and performance shares.
Regulatory Assets and Liabilities	'
	Unless otherwise stated below, all of our regulatory assets earn a return.  Our regulatory assets and liabilities as of September 30, 2014 and December 31, 2013 included the following:
		Remaining		September 30,			December 31,
		Period		2014			2013
				(In Thousands)
	Regulatory Assets:
	Nuclear plant investments – above market	(a)		$	-		$	238,868
	Unamortized redemption costs	7 to 19 years			10,700			11,301
	Pension and other post-retirement benefit plans	(b)			311,033			316,076
	Environmental remediation costs	6 years			14,757			14,953
	Hardship programs	(c)			27,119			25,019
	Debt premium	1 to 24 years			28,763			34,178
	Deferred purchased gas	(d)			-			2,556
	Income taxes due principally to book-tax differences	(m)			155,191			149,015
	Deferred income taxes	(e)			46,734			32,517
	Contracts for differences	(f)			61,163			142,743
	Excess generation service charge	(g)			-			6,909
	Deferred transmission expense	(h)			3,272			9,615
	Storm Costs	(i)			-			14,752
	Other	(j)			32,594			37,628
	Total regulatory assets				691,326			1,036,130
	Less current portion of regulatory assets				69,721			332,391
	Regulatory Assets, Net			$	621,605		$	703,739
	Regulatory Liabilities:
	Accumulated deferred investment tax credits	29 years		$	4,355		$	4,465
	Income taxes due principally to book-tax differences	(m)			-			200,673
	Deferred gain on sale of property	(a)			-			37,933
	Excess generation service charge	(g)			25,296			-
	Middletown/Norwalk local transmission network service collections	35 years			20,972			21,402
	Pension and other post-retirement benefit plans	6 years			24,465			27,686
	Asset retirement obligation	(k)			6,604			5,593
	Low income programs	(l)			30,158			25,300
	Asset removal costs	(j)			333,712			319,530
	Deferred income taxes	(e)			26,247			43,421
	Contracts for differences	(f)			6,608			-
	Deferred purchased gas	(d)			6,596			-
	Non-firm margin sharing credits	10 years			29,339			-
	Other	(j)			29,413			20,818
	Total regulatory liabilities				543,765			706,821
	Less current portion of regulatory liabilities				30,043			261,729
	Regulatory Liabilities, Net			$	513,722		$	445,092
	(a) Asset/Liability relates to the Competitive Transition Assessment (CTA).  Balances are fully offset by amounts primarily included in income taxes, due principally to book-tax differences.  Total CTA costs recovery and stranded cost amortization are complete.  As a result of the outcome of UI’s 2013 distribution rate request, PURA approved UI’s proposed rate treatment to leave CTA rates unchanged until January 1, 2014 at which point the charge ended.  The remaining balances were eliminated.  See Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Other Proceedings” for additional information.
	(b) Life is dependent upon timing of final pension plan distribution; balance, which is fully offset by a corresponding asset/liability, is recalculated each year in accordance with ASC 715 "Compensation-Retirement Benefits." See Note (G) “Pension and Other Benefits” for additional information.
	(c) Hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.
	(d) Deferred purchase gas costs balances at the end of the rate year are normally recorded/returned in the next year.
	(e) The balance will be extinguished when the asset, which is fully offset by a corresponding liability, or liability has been realized or settled, respectively.
	(f) Asset life is equal to delivery term of related contracts (which vary from approximately 6 - 13 years); balance fluctuates based upon quarterly market analysis performed on the related derivatives (Note K); amount, which does not earn a return, is fully offset by corresponding derivative asset/liability.  See “-Contracts for Differences” discussion above for additional information.
	(g) Regulatory asset or liability which defers generation-related and nonbypassable federally mandated congestion costs or revenues for future recovery from or return to customers.  Amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
	(h) Regulatory asset or liability which defers transmission income or expense and fluctuates based upon actual revenues and revenue requirements.
	(i) Storm costs include accumulated costs for major storms occurring from January 2009 forward. See Note (C) “Regulatory Proceedings – Electric Distribution and Transmission – Rates” for a discussion of the recovery of these costs.
	(j) Amortization period and/or balance vary depending on the nature, cost of removal and/or remaining life of the underlying assets/liabilities; asset amount includes decoupling ($5.5 million) and certain other amounts that are not currently earning a return. See Note (C) “Regulatory Proceedings for a discussion of the decoupling recovery period.
	(k) The liability will be extinguished simultaneous with the retirement of the assets and settlement of the corresponding asset retirement obligation.
	(l) Various hardship and payment plan programs approved for recovery.
	(m) Amortization period and/or balance vary depending on the nature and/or remaining life of the underlying assets/liabilities; balances contain regulatory liabilities related to the CTA as well as regulatory assets not related to the CTA.  Due to the end of the CTA charge, the CTA regulatory liabilities are classified as current regulatory liabilities as of December 31, 2013 and the regulatory assets not related to the CTA are reclassified as long-term regulatory assets.

SUPPLEMENTARY_INFORMATION_Tabl

SUPPLEMENTARY INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2014
SUPPLEMENTARY INFORMATION [Abstract]	'
Supplementary Information	'
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2014		2013		2014			2013
		(In Thousands)				(In Thousands)
	Depreciation and Amortization
	Property, plant, and equipment depreciation	$	32,860	$	30,870	$	97,208		$	89,788
	Amortization of regulatory assets		2,718		19,891		15,200			56,749
	Total Depreciation and Amortization	$	35,578	$	50,761	$	112,408		$	146,537
	Taxes - Other than Income Taxes
	Operating:
	Connecticut gross earnings	$	16,199	$	17,780	$	54,671		$	54,873
	Local real estate and personal property		13,310		12,417		37,399			34,416
	Payroll taxes		3,046		2,069		9,877			6,584
	Other		342		123		1,027			462
	Total Taxes - Other than Income Taxes	$	32,897	$	32,389	$	102,974		$	96,335
	Other Income and (Deductions)
	Interest income	$	666	$	243	$	1,731		$	1,449
	Allowance for funds used during construction - equity		1,949		2,751		6,869			8,085
	Allowance for funds used during construction - debt		1,201		1,533		4,032			5,869
	Weather insurance		-		-		(2,437	)		-
	Other		520		626		2,627			315
	Total Other Income and (Deductions)	$	4,336	$	5,153	$	12,822		$	15,718

PENSION_AND_OTHER_BENEFITS_Tab

PENSION AND OTHER BENEFITS (Tables)	9 Months Ended
	Sep. 30, 2014
PENSION AND OTHER BENEFITS [Abstract]	'
Components of Net Periodic Benefit Cost for Pension and Other Postretirement Benefits	'
	The following tables represent the components of net periodic benefit cost for pension and other postretirement benefits as well as the actuarial weighted-average assumptions used in calculating net periodic benefit cost for the three- and nine‑month periods ended September 30, 2014 and 2013:
			Three Months Ended September 30,
			Pension Benefits						Other Postretirement Benefits
			2014			2013			2014			2013
			(In Thousands)
	Components of net periodic benefit cost:
	Service cost		$	2,896		$	3,696		$	404		$	481
	Interest cost			11,019			9,988			1,487			1,384
	Expected return on plan assets			(13,560	)		(12,863	)		(700	)		(648	)
	Amortization of:
	Prior service costs			73			151			71			(13	)
	Actuarial loss			3,097			5,208			(172	)		444
	Settlements (1)			-			632			-			-
	Net periodic benefit cost		$	3,525		$	6,812		$	1,090		$	1,648
			Nine Months Ended September 30,
			Pension Benefits						Other Postretirement Benefits
			2014			2013			2014			2013
			(In Thousands)
	Components of net periodic benefit cost:
	Service cost		$	8,688		$	11,088		$	1,212		$	1,443
	Interest cost			33,057			29,964			4,461			4,152
	Expected return on plan assets			(40,680	)		(38,589	)		(2,100	)		(1,944	)
	Amortization of:
	Prior service costs			219			453			213			(39	)
	Actuarial loss			9,291			15,624			(516	)		1,332
	Settlements (1)			-			632			-			-
	Net periodic benefit cost		$	10,575		$	19,172		$	3,270		$	4,944
			Three and Nine Months Ended September 30,
			Pension Benefits						Other Postretirement Benefits
				2014			2013			2014			2013
	Discount rate			4.90%-5.20	%		4.00%-4.25	%		4.85%-5.20	%		4.00%-4.25	%
	Average wage increase			3.50%-3.80	%		3.50%-3.80	%		N/A			N/A
	Return on plan assets			7.75%-8.00	%		7.75%-8.00	%		5.56%-8.00	%		5.56%-8.00	%
	Composite health care trend rate (current year)			N/A			N/A			7	%		7.5	%
	Composite health care trend rate (2018 forward)			N/A			N/A			5	%		5	%
Weighted Average Actuarial Assumption used in Calculating Net Periodic Benefit Cost	'
			Nine Months Ended September 30,
			Pension Benefits						Other Postretirement Benefits
			2014			2013			2014			2013
			(In Thousands)
	Components of net periodic benefit cost:
	Service cost		$	8,688		$	11,088		$	1,212		$	1,443
	Interest cost			33,057			29,964			4,461			4,152
	Expected return on plan assets			(40,680	)		(38,589	)		(2,100	)		(1,944	)
	Amortization of:
	Prior service costs			219			453			213			(39	)
	Actuarial loss			9,291			15,624			(516	)		1,332
	Settlements (1)			-			632			-			-
	Net periodic benefit cost		$	10,575		$	19,172		$	3,270		$	4,944
			Three and Nine Months Ended September 30,
			Pension Benefits						Other Postretirement Benefits
				2014			2013			2014			2013
	Discount rate			4.90%-5.20	%		4.00%-4.25	%		4.85%-5.20	%		4.00%-4.25	%
	Average wage increase			3.50%-3.80	%		3.50%-3.80	%		N/A			N/A
	Return on plan assets			7.75%-8.00	%		7.75%-8.00	%		5.56%-8.00	%		5.56%-8.00	%
	Composite health care trend rate (current year)			N/A			N/A			7	%		7.5	%
	Composite health care trend rate (2018 forward)			N/A			N/A			5	%		5	%
	-1	Reflects settlement charges resulting from a distribution to a former employee upon retirement
	N/A – not applicable

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2014
FAIR VALUE MEASUREMENTS [Abstract]	'
Fair Value of Financial Assets and Liabilities	'
	The following tables set forth the fair value of our financial assets and liabilities, other than pension benefits and other postretirement benefits, as of September 30, 2014 and December 31, 2013.
		Fair Value Measurements Using
		Quoted Prices in			Significant			Significant			Total
		Active Markets			Other			Unobservable
		for Identical			Observable			Inputs (Level 3)
		Assets (Level 1)			Inputs (Level 2)
	30-Sep-14	(In Thousands)
	Assets:
	Derivative assets	$	-		$	-		$	28,806		$	28,806
	Noncurrent investments		11,249			-			-			11,249
	Deferred Compensation Plan		3,502			-			-			3,502
	Supplemental retirement benefit trust life insurance policies		-			8,259			-			8,259
		$	14,751		$	8,259		$	28,806		$	51,816
	Liabilities:
	Derivative liabilities	$	-		$	-		$	83,352		$	83,352
	Long-term debt		-			1,915,475			-			1,915,475
		$	-		$	1,915,475		$	83,352		$	1,998,827
	Net fair value assets/(liabilities), September 30, 2014	$	14,751		$	(1,907,216	)	$	(54,546	)	$	(1,947,011	)
	31-Dec-13
	Assets:
	Derivative assets	$	-		$	-		$	53,447		$	53,447
	Noncurrent investments		11,148			-			-			11,148
	Deferred Compensation Plan		3,775			-			-			3,775
	Supplemental retirement benefit trust life insurance policies		-			7,898			-			7,898
		$	14,923		$	7,898		$	53,447		$	76,268
	Liabilities:
	Derivative liabilities	$	-		$	-		$	196,233		$	196,233
	Long-term debt		-			1,846,867			-			1,846,867
		$	-		$	1,846,867		$	196,233		$	2,043,100
	Net fair value assets/(liabilities), December 31, 2013	$	14,923		$	(1,838,969	)	$	(142,786	)	$	(1,966,832	)
Additional Quantitative Information about Level 3 Fair Value Measurements	'
	Additional quantitative information about Level 3 fair value measurements is as follows:
				Range at	Range at
		Unobservable Input		30-Sep-14	31-Dec-13
	Contracts for differences	Risk of non-performance		0.00% - 0.64%	0.00% - 0.62%
		Discount rate		1.78% - 2.64%	1.75% - 3.21%
		Forward pricing ($ per MW)		$3.15 - $14.59	$1.40 - $9.83
Changes in Fair Value of Assets and Liabilities Classified as level 3	'
	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 nine-month period ended September 30, 2014.
		Nine Months Ended
		30-Sep-14
		(In Thousands)
	Net derivative assets/(liabilities), December 31, 2013	$	(142,786	)
	Unrealized gains and (losses), net		88,240
	Net derivative assets/(liabilities), September 30, 2014	$	(54,546	)
	Change in unrealized gains (losses), net relating to net derivative assets/(liabilities), still held as of September 30, 2014	$	88,240
Change in Regulatory Asset/(Liability) Balance	'
	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 CfDs for the nine-month period ended September 30, 2014.  The amounts offset the net CfDs liabilities included in the derivative liabilities detailed above.
		Nine Months Ended
		30-Sep-14
		(In Thousands)
	Net regulatory assets/(liabilities), December 31, 2013	$	142,786
	Unrealized (gains) and losses, net		(88,240	)
	Net regulatory assets/(liabilities), September 30, 2014	$	54,546

SEGMENT_INFORMATION_Tables

SEGMENT INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2014
SEGMENT INFORMATION [Abstract]	'
Reconciliation of Operating Profit (Loss) from Segments to Consolidated Financial Statements	'
			Three months ended September 30, 2014
			Electric Distribution and Transmission
			Distribution		Transmission		Total		Gas Distribution			Other			Total
	Operating Revenues		$	134,289	$	62,926	$	197,215	$	94,708		$	1,103		$	293,026
	Purchased power and gas			37,962		-		37,962		30,504			310			68,776
	Operation and maintenance			42,819		11,456		54,275		44,950			(3,974	)		95,251
	Transmission wholesale			-		25,802		25,802		-			-			25,802
	Depreciation and amortization			11,943		4,208		16,151		16,477			2,950			35,578
	Taxes - other than income taxes			14,244		10,441		24,685		9,082			(870	)		32,897
	Acquisition-related expenses			-		-		-		-			570			570
	Operating Income			27,321		11,019		38,340		(6,305	)		2,117			34,152
	Other Income and (Deductions), net			2,877		881		3,758		702			(973	)		3,487
	Interest Charges, net			7,590		3,375		10,965		7,116			5,560			23,641
	Income from Equity Investments			3,492		-		3,492		-			-			3,492
	Income (Loss) Before Income Taxes			26,100		8,525		34,625		(12,719	)		(4,416	)		17,490
	Income Taxes			8,173		3,048		11,221		(6,229	)		(6	)		4,986
	Net Income (Loss)			17,927		5,477		23,404		(6,490	)		(4,410	)		12,504
	Less:
	Preferred Stock Dividends of
	Subsidiary, Noncontrolling Interests			-		-		-		6			-			6
	Net Income (Loss) attributable to UIL Holdings		$	17,927	$	5,477	$	23,404	$	(6,496	)	$	(4,410	)	$	12,498
	Total Capital Expenditures (1)		$	-	$	-	$	31,523	$	32,926		$	6,181		$	70,630
			Three months ended September 30, 2013
			Electric Distribution and Transmission
			Distribution		Transmission		Total		Gas Distribution			Other			Total
	Operating Revenues		$	151,369	$	67,830	$	219,199	$	97,244		$	35		$	316,478
	Purchased power and gas			37,314		-		37,314		37,343			-			74,657
	Operation and maintenance			43,387		11,532		54,919		36,271			(1,380	)		89,810
	Transmission wholesale			-		28,659		28,659		-			-			28,659
	Depreciation and amortization			28,397		4,152		32,549		17,202			1,010			50,761
	Taxes - other than income taxes			13,390		10,466		23,856		8,410			123			32,389
	Rate case disallowances			17,543		-		17,543		-			-			17,543
	Operating Income			11,338		13,021		24,359		(1,982	)		282			22,659
	Other Income and (Deductions), net			3,534		746		4,280		234			639			5,153
	Interest Charges, net			6,088		2,763		8,851		7,507			6,041			22,399
	Income from Equity Investments			3,930		-		3,930		-			-			3,930
	Income (Loss) Before Income Taxes			12,714		11,004		23,718		(9,255	)		(5,120	)		9,343
	Income Taxes			5,607		3,890		9,497		(2,970	)		(2,341	)		4,186
	Net Income (Loss)			7,107		7,114		14,221		(6,285	)		(2,779	)		5,157
	Less:
	Preferred Stock Dividends of
	Subsidiary, Noncontrolling Interests			-		-		-		13			-			13
	Net Income (Loss) attributable to UIL Holdings		$	7,107	$	7,114	$	14,221	$	(6,298	)	$	(2,779	)	$	5,144
	Total Capital Expenditures (1)		$	-	$	-	$	41,310	$	25,968		$	12,910		$	80,188
			Nine months ended September 30, 2014
			Electric Distribution and Transmission
			Distribution		Transmission		Total		Gas Distribution			Other			Total
	Operating Revenues		$	397,384	$	183,715	$	581,099	$	616,780		$	1,103		$	1,198,982
	Purchased power and gas			123,771		-		123,771		321,986			310			446,067
	Operation and maintenance			135,282		36,049		171,331		130,761			(11,264	)		290,828
	Transmission wholesale			-		65,777		65,777		-			-			65,777
	Depreciation and amortization			35,902		12,635		48,537		55,994			7,877			112,408
	Taxes - other than income taxes			38,597		26,832		65,429		37,080			465			102,974
	Acquisition-related expenses			-		-		-		-			6,090			6,090
	Operating Income			63,832		42,422		106,254		70,959			(2,375	)		174,838
	Other Income and (Deductions), net			9,503		2,793		12,296		(587	)		(14,075	)		(2,366	)
	Interest Charges, net			22,661		9,832		32,493		21,320			16,509			70,322
	Income from Equity Investments			10,398		-		10,398		-			-			10,398
	Income (Loss) Before Income Taxes			61,072		35,383		96,455		49,052			(32,959	)		112,548
	Income Taxes			18,015		12,262		30,277		18,749			(13,750	)		35,276
	Net Income (Loss)			43,057		23,121		66,178		30,303			(19,209	)		77,272
	Less:
	Preferred Stock Dividends of
Subsidiary, Noncontrolling Interests			-		-		-		(21	)		-			(21	)
Net Income (Loss) attributable to UIL Holdings		$	43,057	$	23,121	$	66,178	$	30,324		$	(19,209	)	$	77,293
Total Capital Expenditures (1)		$	-	$	-	$	91,600	$	78,278		$	26,293		$	196,171
		Nine months ended September 30, 2013
		Electric Distribution and Transmission
		Distribution		Transmission		Total		Gas Distribution			Other			Total
Operating Revenues		$	421,959	$	180,412	$	602,371	$	581,115		$	105		$	1,183,591
Purchased power and gas			105,996		-		105,996		315,520			-			421,516
Operation and maintenance			132,919		33,212		166,131		111,496			(4,088	)		273,539
Transmission wholesale			-		65,994		65,994		-			-			65,994
Depreciation and amortization			72,924		12,123		85,047		58,515			2,975			146,537
Taxes - other than income taxes			36,860		25,260		62,120		33,769			446			96,335
Rate case disallowances			17,543		-		17,543		-			-			17,543
Operating Income			55,717		43,823		99,540		61,815			772			162,127
Other Income and (Deductions), net			10,687		3,465		14,152		(298	)		1,864			15,718
Interest Charges, net			19,834		9,104		28,938		22,415			18,180			69,533
Income from Equity Investments			11,590		-		11,590		-			-			11,590
Income (Loss) Before Income Taxes			58,160		38,184		96,344		39,102			(15,544	)		119,902
Income Taxes			24,464		13,474		37,938		14,770			(7,704	)		45,004
Net Income (Loss)			33,696		24,710		58,406		24,332			(7,840	)		74,898
Less:
Preferred Stock Dividends of
Subsidiary, Noncontrolling Interests			-		-		-		39			-			39
Net Income (Loss) attributable to UIL Holdings		$	33,696	$	24,710	$	58,406	$	24,293		$	(7,840	)	$	74,859
Total Capital Expenditures (1)		$	-	$	-	$	124,437	$	63,771		$	35,964		$	224,172
		Electric Distribution and Transmission (2)
		Distribution		Transmission		Total		Gas Distribution (3)			Other			Total (3)
Total Assets at September 30, 2014		$	-	$	-	$	2,709,623	$	1,996,825		$	151,293		$	4,857,741
Total Assets at December 31, 2013		$	-	$	-	$	2,950,707	$	2,010,246		$	183,267		$	5,144,220
Reconciliation of Total Assets from Segments to Consolidated Financial Statements	'
			Electric Distribution and Transmission (2)
			Distribution		Transmission		Total		Gas Distribution (3)			Other			Total (3)
	Total Assets at September 30, 2014		$	-	$	-	$	2,709,623	$	1,996,825		$	151,293		$	4,857,741
	Total Assets at December 31, 2013		$	-	$	-	$	2,950,707	$	2,010,246		$	183,267		$	5,144,220
	-1	Information for segmenting total capital expenditures between Distribution and Transmission is not available.  Total Electric Distribution and Transmission capital expenditures are disclosed in the Total Electric Distribution and Transmission column.
	-2	Information for segmenting total assets between Distribution and Transmission is not available.  Total Electric Distribution and Transmission assets are disclosed in the Total Electric and Distribution and Transmission column.  Net plant in service is segregated by segment and, as of September 30, 2014, was $1,236.8 million and $658.2 million for Distribution and Transmission, respectively.  As of December 31, 2013, net plant in service was $1,181.1 million and $656.0 million for Distribution and Transmission, respectively.
	-3	Includes $266.2 million of goodwill in the Gas Distribution segment as of September 30, 2014 and December 31, 2013.

BUSINESS_ORGANIZATION_AND_STAT3

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES (Details) (USD $)	3 Months Ended		9 Months Ended				9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Mar. 02, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
					Philadelphia Gas Works [Member]	Philadelphia Gas Works [Member]	Philadelphia Gas Works [Member]	Philadelphia Gas Works [Member]	Milford LNG [Member]
							Bridge Facility [Member]	Operating Expense [Member]	gal
Ownership percentage in GenConn [Abstract]	'	'	'	'	'	'	'	'	'
Ownership percentage in joint venture (in hundredths)	50.00%	'	50.00%	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'
Initial purchase price	'	'	'	'	'	$1,860,000,000	'	'	'
Acquisition related expenses	570,000	0	6,090,000	0	21,300,000	'	15,200,000	6,100,000	'
Capacity of storage tank acquired	'	'	'	'	'	'	'	'	14,600,000
Inventory acquired for cash purchase price	'	'	$20,110,000	$0	'	'	'	'	$20,110,000

BUSINESS_ORGANIZATION_AND_STAT4

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES, DERIVATIVES, EARNINGS PER SHARE (Details) (USD $)

3 Months Ended

9 Months Ended

Share data in Thousands, except Per Share data, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Oct. 31, 2013

Contract

Contract

Current Assets [Member]

Current Assets [Member]

Deferred Charges and Other Assets [Member]

Deferred Charges and Other Assets [Member]

Current Liabilities [Member]

Current Liabilities [Member]

Noncurrent Liabilities [Member]

Noncurrent Liabilities [Member]

Weather Insurance Contracts [Member]

Weather Insurance Contracts [Member]

Weather Insurance Contracts [Member]

Weather Insurance Contracts [Member]

CapacityResource

CapacityResource

Southern Connecticut Gas Company (SCG) [Member]

Southern Connecticut Gas Company (SCG) [Member]

Berkshire [Member]

Berkshire [Member]

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross derivative asset

$28,800,000

'

$28,800,000

'

$6,861,000

$9,098,000

$21,945,000

$44,349,000

'

'

'

'

'

'

'

'

Regulatory asset

61,200,000

'

61,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross derivative liability

83,400,000

'

83,400,000

'

'

'

'

'

23,404,000

26,976,000

59,948,000

169,327,000

'

'

'

'

Gross derivative asset, UIL's portion of entity

6,700,000

'

6,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross derivative liability, UIL's portion of entity

55,700,000

'

55,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory liabilities

6,600,000

'

6,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum receivable amount allowed under weather insurance contract

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

'

1,000,000

'

Intrinsic value of contract

'

'

'

'

'

'

'

'

'

'

'

'

'

2,000,000

'

200,000

Derivatives [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of new capacity resources selected

4

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Contracts for Differences (CfDs) approved by Public Utility Regulatory Authority (PURA)

4

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Contracts for Differences (CfDs) executed by UI

2

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Contracts for Differences (CfDs) executed by CL&P

2

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of cost borne by UI customers for CFDs (in hundredths)

'

'

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of cost borne by CL&P customers (in hundredths)

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrealized gain and losses from mark-to-market adjustments [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory Assets - Derivative liability

393,000

-5,585,000

-81,623,000

-28,849,000

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory Liabilities - Derivative assets

5,077,000

0

-6,616,000

0

'

'

'

'

'

'

'

'

'

'

'

'

Numerator [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income attributable to UIL Holdings

12,498,000

5,144,000

77,293,000

74,859,000

'

'

'

'

'

'

'

'

'

'

'

'

Less: Net income allocated to unvested units

7,000

5,000

45,000

83,000

'

'

'

'

'

'

'

'

'

'

'

'

Net income attributable to common shareholders

$12,491,000

$5,139,000

$77,248,000

$74,776,000

'

'

'

'

'

'

'

'

'

'

'

'

Denominator [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Basic average number of shares outstanding (in shares)

56,855

50,989

56,827

50,956

'

'

'

'

'

'

'

'

'

'

'

'

Effect of dilutive securities (in shares)

278

[1]

242

[1]

287

[1]

281

[1]

'

'

'

'

'

'

'

'

'

'

'

'

Diluted average number of shares outstanding (in shares)

57,133

51,231

57,114

51,237

'

'

'

'

'

'

'

'

'

'

'

'

Earnings per share [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Basic (in dollars per share)

$0.22

$0.10

$1.36

$1.47

'

'

'

'

'

'

'

'

'

'

'

'

Diluted (in dollars per share)

$0.22

$0.10

$1.35

$1.46

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Includes unvested restricted stock and performance shares.

BUSINESS_ORGANIZATION_AND_STAT5

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES, EQUITY INVESTMENTS (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Equity Investments [Abstract]	'	'	'	'	'
Carrying value of joint venture	$114,305,000	'	$114,305,000	'	$118,241,000
Income (loss) from equity investment	3,492,000	3,930,000	10,398,000	11,590,000	'
GenConn [Member]	'	'	'	'	'
Equity Investments [Abstract]	'	'	'	'	'
Number of peaking generation plants	2	'	2	'	'
Carrying value of joint venture	114,300,000	'	114,300,000	'	118,200,000
Undistributed earnings in equity method investment	100,000	'	100,000	'	'
Income (loss) from equity investment	3,500,000	3,900,000	10,400,000	11,600,000	'
Distributions received from joint venture	$5,500,000	$0	$14,300,000	$9,800,000	'

BUSINESS_ORGANIZATION_AND_STAT6

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES, REGULATORY ASSETS (Details) (USD $)	9 Months Ended
	Sep. 30, 2014		Dec. 31, 2013
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	$691,326,000		$1,036,130,000
Less current portion of regulatory assets	69,721,000		332,391,000
Regulatory Assets, Net	621,605,000		703,739,000
Assets decoupling amount	5,500,000		'
Nuclear Plant Investments - Above Market [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	0	[1]	238,868,000	[1]
Unamortized Redemption Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	10,700,000		11,301,000
Remaining period, minimum	'7 years		'
Remaining period, maximum	'19 years		'
Pension and Other Post-Retirement Benefit Plans [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	311,033,000	[2]	316,076,000	[2]
Environmental Remediation Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	14,757,000		14,953,000
Remaining period	'3 years		'
Hardship Programs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	27,119,000	[3]	25,019,000	[3]
Debt Premium [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	28,763,000		34,178,000
Remaining period, minimum	'1 year		'
Remaining period, maximum	'24 years		'
Deferred Purchased Gas [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	0	[4]	2,556,000	[4]
Income Taxes Due Principally to Book Tax Differences Assets [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	155,191,000	[5]	149,015,000	[5]
Deferred Income Taxes [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	46,734,000	[6]	32,517,000	[6]
Contracts For Differences [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	61,163,000	[7]	142,743,000	[7]
Term of contract minimum	'6 years		'
Term of contract maximum	'13 years		'
Excess Generation Service Charge [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	0	[8]	6,909,000	[8]
Deferred Transmission Income/Expense [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	3,272,000	[9]	9,615,000	[9]
Storm Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	0	[10]	14,752,000	[10]
Other [Member]	'		'
Regulatory Assets [Line Items]	'		'
Total Regulatory Assets	$32,594,000	[11]	$37,628,000	[11]
[1]	Asset/Liability relates to the Competitive Transition Assessment (CTA). Balances are fully offset by amounts primarily included in income taxes, due principally to book-tax differences. Total CTA costs recovery and stranded cost amortization are complete. As a result of the outcome of UI's 2013 distribution rate request, PURA approved UI's proposed rate treatment to leave CTA rates unchanged until January 1, 2014 at which point the charge ended. The remaining balances were eliminated. See Note (C) "Regulatory Proceedings - Electric Distribution and Transmission - Other Proceedings" for additional information.
[2]	Life is dependent upon timing of final pension plan distribution; balance, which is fully offset by a corresponding asset/liability, is recalculated each year in accordance with ASC 715 "Compensation-Retirement Benefits." See Note (G) "Pension and Other Benefits" for additional information.
[3]	Hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.
[4]	Deferred purchase gas costs balances at the end of the rate year are normally recorded/returned in the next year.
[5]	Amortization period and/or balance vary depending on the nature and/or remaining life of the underlying assets/liabilities; balances contain regulatory liabilities related to the CTA as well as regulatory assets not related to the CTA. Due to the end of the CTA charge, the CTA regulatory liabilities are classified as current regulatory liabilities as of December 31, 2013 and the regulatory assets not related to the CTA are reclassified as long-term regulatory assets.
[6]	The balance will be extinguished when the asset, which is fully offset by a corresponding liability, or liability has been realized or settled, respectively.
[7]	Asset life is equal to delivery term of related contracts (which vary from approximately 6 - 13 years); balance fluctuates based upon quarterly market analysis performed on the related derivatives (Note K); amount, which does not earn a return, is fully offset by corresponding derivative asset/liability. See "-Contracts for Differences" discussion above for additional information.
[8]	Regulatory asset or liability which defers generation-related and nonbypassable federally mandated congestion costs or revenues for future recovery from or return to customers. Amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
[9]	Regulatory asset or liability which defers transmission income or expense and fluctuates based upon actual revenues and revenue requirements.
[10]	Storm costs include accumulated costs for major storms occurring from January 2009 forward. See Note (C) "Regulatory Proceedings - Electric Distribution and Transmission - Rates" for a discussion of the recovery of these costs.
[11]	Amortization period and/or balance vary depending on the nature, cost of removal and/or remaining life of the underlying assets/liabilities; asset amount includes decoupling ($5.5 million) and certain other amounts that are not currently earning a return. See Note (C) "Regulatory Proceedings" for a discussion of the decoupling recovery period.

BUSINESS_ORGANIZATION_AND_STAT7

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES, REGULATORY LIABILITIES (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	$543,765		$706,821
Less current portion of regulatory liabilities	30,043		261,729
Regulatory Liabilities, Net	513,722		445,092
Accumulated Deferred Investment Tax Credits [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	4,355		4,465
Remaining period	'29 years		'
Income Taxes Due Principally to Book-Tax Differences [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	0	[1]	200,673	[1]
Deferred Gain on Sale of Property [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	0	[2]	37,933	[2]
Excess Generation Service Charge [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	25,296	[3]	0	[3]
Middletown/Norwalk Local Transmission Network Service Collections [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	20,972		21,402
Remaining period	'35 years		'
Pension and Other Post-Retirement Benefit Plans [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	24,465		27,686
Remaining period	'6 years		'
Asset Retirement Obligation [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	6,604	[4]	5,593	[4]
Low Income Programs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	30,158	[5]	25,300	[5]
Asset Removal Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	333,712	[6]	319,530	[6]
Deferred Income Taxes [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	26,247	[7]	43,421	[7]
Contracts For Differences [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	6,608	[8]	0	[8]
Deferred Purchased Gas [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	6,596	[9]	0	[9]
Non-Firm Margin Sharing Credits [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	29,339		0
Remaining period	'10 years		'
Other [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Total regulatory liabilities	$29,413	[6]	$20,818	[6]
[1]	Amortization period and/or balance vary depending on the nature and/or remaining life of the underlying assets/liabilities; balances contain regulatory liabilities related to the CTA as well as regulatory assets not related to the CTA. Due to the end of the CTA charge, the CTA regulatory liabilities are classified as current regulatory liabilities as of December 31, 2013 and the regulatory assets not related to the CTA are reclassified as long-term regulatory assets.
[2]	Asset/Liability relates to the Competitive Transition Assessment (CTA). Balances are fully offset by amounts primarily included in income taxes, due principally to book-tax differences. Total CTA costs recovery and stranded cost amortization are complete. As a result of the outcome of UI's 2013 distribution rate request, PURA approved UI's proposed rate treatment to leave CTA rates unchanged until January 1, 2014 at which point the charge ended. The remaining balances were eliminated. See Note (C) "Regulatory Proceedings - Electric Distribution and Transmission - Other Proceedings" for additional information.
[3]	Regulatory asset or liability which defers generation-related and nonbypassable federally mandated congestion costs or revenues for future recovery from or return to customers. Amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
[4]	The liability will be extinguished simultaneous with the retirement of the assets and settlement of the corresponding asset retirement obligation.
[5]	Various hardship and payment plan programs approved for recovery.
[6]	Amortization period and/or balance vary depending on the nature, cost of removal and/or remaining life of the underlying assets/liabilities; asset amount includes decoupling ($5.5 million) and certain other amounts that are not currently earning a return. See Note (C) "Regulatory Proceedings" for a discussion of the decoupling recovery period.
[7]	The balance will be extinguished when the asset, which is fully offset by a corresponding liability, or liability has been realized or settled, respectively.
[8]	Asset life is equal to delivery term of related contracts (which vary from approximately 6 - 13 years); balance fluctuates based upon quarterly market analysis performed on the related derivatives (Note K); amount, which does not earn a return, is fully offset by corresponding derivative asset/liability. See "-Contracts for Differences" discussion above for additional information.
[9]	Deferred purchase gas costs balances at the end of the rate year are normally recorded/returned in the next year.

BUSINESS_ORGANIZATION_AND_STAT8

BUSINESS ORGANIZATION AND STATEMENT OF ACCOUNTING POLICIES, STOCK BASED COMPENSATION (Details) (USD $)	3 Months Ended	9 Months Ended		1 Months Ended						3 Months Ended	1 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Jun. 30, 2014	Jun. 30, 2014	Aug. 31, 2014	31-May-14	Mar. 31, 2014	Mar. 31, 2014	Sep. 30, 2014	31-May-14
				Performance Shares [Member]	Restricted Stock [Member]	Management [Member]	Management [Member]	Management [Member]	President and Chief Executive Officer [Member]	President and Chief Executive Officer [Member]	Non-Employee Directors [Member]
						Performance Shares [Member]	Performance Shares [Member]	Performance Shares [Member]	Restricted Stock [Member]	Restricted Stock [Member]	Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Number of shares granted (in shares)	'	'	'	'	'	2,340	2,430	123,940	2,196	'	25,160
Weighted average grant date fair value (in dollars per share)	'	'	'	'	'	$34.90	$36.23	$35.87	$35.87	'	$35.90
Number of shares forfeited (in shares)	'	'	'	9,540	2,177	'	'	'	'	'	'
Vesting period	'	'	'	'	'	'	'	'	'	'5 years	'
Vesting rights	'	'	'	'	'	'	'	'	'	'equal annual installments over a five year period	'
Total stock-based compensation expense	$1.10	$3.40	$4.10	'	'	'	'	'	'	'	'

CAPITALIZATION_Details

CAPITALIZATION (Details) (USD $)	9 Months Ended		1 Months Ended		1 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Aug. 31, 2014	Sep. 30, 2014	Aug. 31, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
			8.12 % Medium Term Notes [Member]	8.12 % Medium Term Notes [Member]	8.49 %Medium Term Notes [Member]	8.49 %Medium Term Notes [Member]	CNG, 8.00% Noncallable [Member]	Common Stock [Member]
			Series B [Member]	Series B [Member]	Series B [Member]	Series B [Member]
Temporary Equity [Line Items]	'	'	'	'	'	'	'	'
Common stock outstanding (in shares)	'	'	'	'	'	'	'	56,546,266
Common stock par value (in dollars per share)	'	'	'	'	'	'	'	$0
Long-term Debt [Abstract]	'	'	'	'	'	'	'	'
Long term debt interest percentage (in hundredths)	'	'	'	8.12%	'	8.49%	'	'
Long term debt redeemed	$10,000,000	$20,000,000	$5,000,000	'	$5,000,000	'	'	'
Preferred Stock of Subsidiaries, Noncontrolling Interests [Abstract]	'	'	'	'	'	'	'	'
Stock authorized (in shares)	'	'	'	'	'	'	884,315	'
Dividend rate of preferred stock (in hundredths)	'	'	'	'	'	'	8.00%	'
Preferred Stock, Par value per share (in dollars per share)	'	'	'	'	'	'	$3.13	'
Preferred Stock, Shares issued (in shares)	'	'	'	'	'	'	108,706	'
Preferred Stock, Shares outstanding (in shares)	'	'	'	'	'	'	108,706	'
Preferred Stock, Value of shares issued	'	'	'	'	'	'	300,000	'
Preferred Stock, Value of shares outstanding	'	'	'	'	'	'	300,000	'
Preferred stock acquired (in shares)	'	'	'	'	'	'	70,699	'
Offering price in purchase of preferred shares (in dollars per share)	'	'	'	'	'	'	$10.25	'
Offering price in purchase of preferred stock, amount	'	'	'	'	'	'	$700,000	'

REGULATORY_PROCEEDINGS_Details

REGULATORY PROCEEDINGS (Details) (USD $)

0 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

9 Months Ended

9 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Feb. 15, 2013

Dec. 16, 2013

Aug. 14, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Jul. 31, 2014

Feb. 28, 2013

Sep. 30, 2012

Sep. 30, 2013

Oct. 02, 2014

Oct. 21, 2014

Oct. 02, 2014

Oct. 02, 2014

Sep. 30, 2014

Sep. 30, 2014

Jan. 22, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Jun. 19, 2014

Jun. 19, 2014

Jun. 19, 2014

Jun. 19, 2014

Jun. 19, 2014

Jun. 19, 2014

Jun. 19, 2014

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

United Illuminating Company (UI) [Member]

Connecticut Natural Gas Corporation (CNG) [Member]

Connecticut Natural Gas Corporation (CNG) [Member]

Connecticut Natural Gas Corporation (CNG) [Member]

Connecticut Natural Gas Corporation (CNG) [Member]

The Southern Connecticut Gas Company (SCG) [Member]

The Berkshire Gas Company [Member]

GenConn Devon [Member]

GenConn Middletown [Member]

New England Transmission Owners [Member]

New England Transmission Owners [Member]

New England Transmission Owners [Member]

New England Transmission Owners [Member]

New England Transmission Owners [Member]

New England Transmission Owners [Member]

New England Transmission Owners [Member]

Project

Contract

2013 Rate Case Decision [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Minimum [Member]

Maximum [Member]

Mechanism

Minimum [Member]

Maximum [Member]

Second Complaint [Member]

Third Complaint [Member]

June 2014 FERC Order [Member]

October 2014 FERC Order [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Megawatt

Bidder

2014 GSC Decision [Member]

June 2014 FERC Order [Member]

June 2014 FERC Order [Member]

October 2014 FERC Order [Member]

Plant

Project

Megawatt

Plant

Rates [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Length of time for proposed rate amendment

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Schedule of Regulatory Proceedings [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowed distribution return on equity (in hundredths)

'

'

8.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowed distribution return on equity per 2013 final decision (in hundredths)

'

'

9.15%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Earnings share split of profit

'

'

'50/50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Disallowance of deferred storm costs and capital costs per PURA final decision rate case

'

'

$22

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Write-off related to disallowance of deferred storm costs and capital costs per PURA final decision in rate case, pre-tax

'

'

'

'

'

'

'

'

'

'

'

17.5

'

'

'

3.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restoration of disallowed deferred storm costs per PURA final decision rate case

'

6.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restoration of disallowed capital costs per PURA final decision rate case

'

2.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reversal of write-off related to deferred storm costs and capital costs per PURA final reconsideration decision

'

'

'

'

9.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowed recovery of storm costs, per PURA final decision rate case

'

45

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Power Supply Arrangements [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of standard service customers with wholesale power supply agreements in place for the first half of 2015 (in hundredths)

'

'

'

'

'

'

70.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2015 (in hundredths)

'

'

'

'

'

'

30.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Collateral required to be posted if the entity's credit rating declined two ratings to fall below investment grade

'

'

'

9.7

'

'

9.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

New Renewable Source Generation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum amount of commitment to purchase Renewable Energy Credits (RECs) from new facilities behind distribution customer meters

'

'

'

200

'

'

200

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period of commitment to purchase Renewable Energy Credits (RECs)

'

'

'

'

'

'

'21 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Solicitation period obligations will phase-in

'

'

'

'

'

'

'6 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum annual commitment level obligation after year six

'

'

'

13.6

'

'

13.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of megawatts of grid connected renewable energy allowed to be developed by UI (in MW)

'

'

'

10

'

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of proposed budget to develop initial energy by UI which has been approved by PURA

'

'

'

35

'

'

35

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of megawatts to be developed in initial stage by UI which has been approved by PURA (in MW)

'

'

'

7.8

'

'

7.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Basis point added to return on equity (in hundredths)

'

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of winning bidders approved by PURA

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of UI's distribution load represented by quantity of energy and RECs to be purchased (in hundredths)

'

'

'

'

'

'

3.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of long term contracts to purchase RECs from existing biomass facilities

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of megawatts energy to be produced by existing biomass facilities (in MW)

'

'

'

5.7

'

'

5.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Transmission [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average return on equity (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12.00%

12.20%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current approved base return on equity (in hundredths)

'

'

'

11.14%

'

'

11.14%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Return on equity sought by complainants (in hundredths)

'

'

'

9.20%

'

'

9.20%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Return on equity per initial decision for refund period of October 1, 2011 through December 31, 2012 (in hundredths)

'

'

'

'

'

'

10.60%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Return on equity, per initial decision, for the period after final opinion issued by FERC (in hundredths)

'

'

'

'

'

'

9.70%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period of U.S. Treasury Bond rates

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reserve recorded by UI for refund

'

'

'

5.3

'

2.6

5.3

2.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reasonable base ROE (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.57%

10.57%

7.03%

11.74%

11.74%

Revised return on equity sought by complainants (in hundredths)

'

'

'

8.70%

'

'

8.70%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Refund period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 Months

'15 Months

'

'

'

'

'

Revised return on equity sought by complainants in third complaint, minimum

'

'

'

'

'

'

'

'

8.84%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revised return on equity sought by complainants in third complaint, maximum

'

'

'

'

'

'

'

'

9.44%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

New England East-West Solution [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of inter related transmission projects

'

'

'

4

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of inter-related transmission projects with portions sited in Connecticut

'

'

'

3

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum amount of entity's investment for ownership of specific transmission assets

'

'

'

60

'

'

60

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Threshold percentage of CL&P's costs for the Connecticut portions of projects (in hundredths)

'

'

'

8.40%

'

'

8.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected amount of investment

'

'

'

45

'

'

45

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cumulative amount of deposits

'

'

'

40.2

'

'

40.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of transmission assets

'

'

'

24.6

'

'

24.6

'

'

18.4

6.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pre-tax income earned on each deposit in NEEWS project

'

'

'

0.5

'

0.3

1.2

1.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Investment in Peaking Generation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ratio of equity investment in peaking generation for joint venture

'

'

'

'

'

'

'50-50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of peaking generation plants

'

'

'

2

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue requirements for equity investment in peaking generation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30.8

37.5

'

'

'

'

'

'

'

Other Proceedings [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount approved for recovery

'

'

'

'

'

'

'

'

'

'

'

'

8.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total estimated loss

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pre-tax write-off

'

'

'

'

'

'

'

'

'

'

'

17.5

'

'

'

3.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Remaining CTA regulatory liability

'

'

'

'

'

'

'

'

'

'

'

'

'

8.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory liability related to storm recovery

'

'

'

'

'

'

'

'

'

'

'

'

'

12

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gas Distribution Rates [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Approved return on equity (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.18%

'

'

9.36%

10.50%

'

'

'

'

'

'

'

'

'

Duration of approved rate plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

Number of rate making mechanisms

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Earnings share mechanism ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'50/50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decrease in annual revenue requirements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$2.50

$3.50

'

'

'

'

'

'

'

'

'

'

'

SHORTTERM_CREDIT_ARRANGEMENTS_

SHORT-TERM CREDIT ARRANGEMENTS (Details) (USD $)	9 Months Ended
	Sep. 30, 2014
UIL [Member]	'
Disclosure of short-term credit arrangements [Abstract]	'
Maximum debt restriction amount	$1,600,000,000
Debt instrument, consolidated debt to consolidated capital ratio	0.77
Number of days of loan term agreement	'364 days
Standby Letters of Credit Due in June 2015 [Member]	'
Disclosure of short-term credit arrangements [Abstract]	'
Expiration date	16-Jun-15
Standby Letter of Credit Due 2015 [Member]	'
Disclosure of short-term credit arrangements [Abstract]	'
Standby letters of credit outstanding	4,400,000
Expiration date	31-Jan-15
Revolving Credit Facility [Member]	'
Disclosure of short-term credit arrangements [Abstract]	'
Expiration date	30-Nov-16
Available credit under the Credit Facility	385,600,000
Amounts outstanding under the Credit Facility	10,000,000
Bridge Facility [Member]	'
Disclosure of short-term credit arrangements [Abstract]	'
Amounts outstanding under the Credit Facility	0
Maximum borrowing capacity	1,900,000,000
Bridge Facility [Member] | WGP [Member]	'
Disclosure of short-term credit arrangements [Abstract]	'
Borrowing limit	$950,000,000

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
INCOME TAXES [Abstract]	'	'
Fluctuation in income tax	$9.70	'
Effective book income tax rates (in hundredths)	32.90%	37.90%

SUPPLEMENTARY_INFORMATION_Deta

SUPPLEMENTARY INFORMATION (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Depreciation and Amortization	'	'	'	'
Property, plant and equipment depreciation	$32,860	$30,870	$97,208	$89,788
Amortization of regulatory assets	2,718	19,891	15,200	56,749
Total Depreciation and Amortization	35,578	50,761	112,408	146,537
Taxes - Other than Income Taxes - Operating:	'	'	'	'
Connecticut gross earnings	16,199	17,780	54,671	54,873
Local real estate and personal property	13,310	12,417	37,399	34,416
Payroll taxes	3,046	2,069	9,877	6,584
Other	342	123	1,027	462
Total Taxes - Other than Income Taxes	32,897	32,389	102,974	96,335
Other Income and (Deductions)	'	'	'	'
Interest income	666	243	1,731	1,449
Allowance for funds used during construction - equity	1,949	2,751	6,869	8,085
Allowance for funds used during construction - debt	1,201	1,533	4,032	5,869
Weather insurance	0	0	-2,437	0
Other	520	626	2,627	315
Total Other Income and (Deductions)	$4,336	$5,153	$12,822	$15,718

PENSION_AND_OTHER_BENEFITS_Det

PENSION AND OTHER BENEFITS (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'
Pension contributions	'		'		$23,000,000		'
Additional contribution during remainder of 2014	'		'		0		'
Pension Benefit [Member]	'		'		'		'
Components of net periodic benefit cost:	'		'		'		'
Service cost	2,896,000		3,696,000		8,688,000		11,088,000
Interest cost	11,019,000		9,988,000		33,057,000		29,964,000
Expected return on plan assets	-13,560,000		-12,863,000		-40,680,000		-38,589,000
Amortization of:	'		'		'		'
Prior service costs	73,000		151,000		219,000		453,000
Actuarial loss	3,097,000		5,208,000		9,291,000		15,624,000
Settlements	0	[1]	632,000	[1]	0	[1]	632,000	[1]
Net periodic benefit cost	3,525,000		6,812,000		10,575,000		19,172,000
Pension Benefit [Member] | Minimum [Member]	'		'		'		'
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]	'		'		'		'
Discount rate (in hundredths)	4.90%		4.00%		4.90%		4.00%
Average wage increase (in hundredths)	3.50%		3.50%		3.50%		3.50%
Return on plan assets (in hundredths)	7.75%		7.75%		7.75%		7.75%
Pension Benefit [Member] | Maximum [Member]	'		'		'		'
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]	'		'		'		'
Discount rate (in hundredths)	5.20%		4.25%		5.20%		4.25%
Average wage increase (in hundredths)	3.80%		3.80%		3.80%		3.80%
Return on plan assets (in hundredths)	8.00%		8.00%		8.00%		8.00%
Other Postretirement Benefits [Member]	'		'		'		'
Components of net periodic benefit cost:	'		'		'		'
Service cost	404,000		481,000		1,212,000		1,443,000
Interest cost	1,487,000		1,384,000		4,461,000		4,152,000
Expected return on plan assets	-700,000		-648,000		-2,100,000		-1,944,000
Amortization of:	'		'		'		'
Prior service costs	71,000		-13,000		213,000		-39,000
Actuarial loss	-172,000		444,000		-516,000		1,332,000
Settlements	0	[1]	0	[1]	0	[1]	0	[1]
Net periodic benefit cost	$1,090,000		$1,648,000		$3,270,000		$4,944,000
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]	'		'		'		'
Composite health care trend rate (current year) (in hundredths)	7.00%		7.50%		7.00%		7.50%
Composite health care trend rate (2018 forward) (in hundredths)	5.00%		5.00%		5.00%		5.00%
Other Postretirement Benefits [Member] | Minimum [Member]	'		'		'		'
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]	'		'		'		'
Discount rate (in hundredths)	4.85%		4.00%		4.85%		4.00%
Return on plan assets (in hundredths)	5.56%		5.56%		5.56%		5.56%
Other Postretirement Benefits [Member] | Maximum [Member]	'		'		'		'
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]	'		'		'		'
Discount rate (in hundredths)	5.20%		4.25%		5.20%		4.25%
Return on plan assets (in hundredths)	8.00%		8.00%		8.00%		8.00%
[1]	Reflects settlement charges resulting from a distribution to a former employee upon retirement

RELATED_PARTY_TRANSACTIONS_Det

RELATED PARTY TRANSACTIONS (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
RELATED PARTY TRANSACTIONS [Abstract]	'	'	'	'
Lease payments for office space	$0.40	$0.40	$1.40	$1.10

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
	Subcontractor
Connecticut Yankee Atomic Power Company [Member]	'
Site Contingency [Line Items]	'
Percentage stock ownership share in CT Yankee atomic power company (in hundredths)	9.50%
Carrying value of stock in CT Yankee atomic power company	$0.20
DOE spent fuel litigation [Abstract]	'
Damages awarded for spent fuel related costs	39.7
Entity's share of amount awarded to CT Yankee atomic power company	3.8
Actual second set of damages award	126.3
Entity's share of second set of damage claims	12
Mill River New Haven Connecticut Site [Member]	'
Site Decontamination, Demolition and Remediation Costs [Abstract]	'
Amount placed in escrow for estimated remediation	1.9
Remaining amount of escrow	0.1
New Haven Harbor Station Site [Member]	'
Site Decontamination, Demolition and Remediation Costs [Abstract]	'
Site contingency, liability accrued	3.2
Mill Street Greenfield Massachusetts Site [Member]	'
Site Decontamination, Demolition and Remediation Costs [Abstract]	'
Site contingency, liability accrued	2.9
East Street Site Pittsfield Massachusetts [Member]	'
Site Decontamination, Demolition and Remediation Costs [Abstract]	'
Site contingency, liability accrued	1.2
Middletown/Norwalk Transmission Projects [Member]	'
Middletown/Norwalk Transmission Project [Abstract]	'
Amount sought for change order requests	33.3
Percentage of general contractor mark-up on approved subcontractor change order claims (in hundredths)	10.00%
Amount of general contractor mark up on approved subcontractor change order claims	2.3
Subcontractors responsible for civil construction	2
Revised estimate for change order requests	7.7
Amount in Memorandum of Decision issued by the court for the company to pay to contractor	$1.30

FAIR_VALUE_MEASUREMENTS_Detail

FAIR VALUE MEASUREMENTS (Details) (Fair Value, Measurements, Recurring [Member], USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Assets: [Abstract]	'	'
Derivative assets	$28,806	$53,447
Noncurrent investments	11,249	11,148
Deferred Compensation Plan	3,502	3,775
Supplemental retirement benefit trust life insurance policies	8,259	7,898
Total financial assets, fair value	51,816	76,268
Liabilities: [Abstract]	'	'
Derivative liabilities	83,352	196,233
Long-term debt	1,915,475	1,846,867
Total financial liabilities, fair value	1,998,827	2,043,100
Net fair value assets/(liabilities)	-1,947,011	-1,966,832
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'	'
Assets: [Abstract]	'	'
Derivative assets	0	0
Noncurrent investments	11,249	11,148
Deferred Compensation Plan	3,502	3,775
Supplemental retirement benefit trust life insurance policies	0	0
Total financial assets, fair value	14,751	14,923
Liabilities: [Abstract]	'	'
Derivative liabilities	0	0
Long-term debt	0	0
Total financial liabilities, fair value	0	0
Net fair value assets/(liabilities)	14,751	14,923
Significant Other Observable Inputs (Level 2) [Member]	'	'
Assets: [Abstract]	'	'
Derivative assets	0	0
Noncurrent investments	0	0
Deferred Compensation Plan	0	0
Supplemental retirement benefit trust life insurance policies	8,259	7,898
Total financial assets, fair value	8,259	7,898
Liabilities: [Abstract]	'	'
Derivative liabilities	0	0
Long-term debt	1,915,475	1,846,867
Total financial liabilities, fair value	1,915,475	1,846,867
Net fair value assets/(liabilities)	-1,907,216	-1,838,969
Significant Unobservable Inputs (Level 3) [Member]	'	'
Assets: [Abstract]	'	'
Derivative assets	28,806	53,447
Noncurrent investments	0	0
Deferred Compensation Plan	0	0
Supplemental retirement benefit trust life insurance policies	0	0
Total financial assets, fair value	28,806	53,447
Liabilities: [Abstract]	'	'
Derivative liabilities	83,352	196,233
Long-term debt	0	0
Total financial liabilities, fair value	83,352	196,233
Net fair value assets/(liabilities)	($54,546)	($142,786)

FAIR_VALUE_MEASUREMENTS_Unobse

FAIR VALUE MEASUREMENTS, Unobservable Input Reconciliation (Details) (Contract For Difference [Member], USD $)	Sep. 30, 2014	Dec. 31, 2013
Contract For Difference [Member]	'	'
Unobservable Input [Abstract]	'	'
Risk of non-performance, lower range (in hundredths)	0.00%	0.00%
Risk of non-performance, upper range (in hundredths)	0.64%	0.62%
Discount rate, lower range (in hundredths)	1.78%	1.75%
Discount rate, upper range (in hundredths)	2.64%	3.21%
Forward pricing, lower range (in dollars per MW)	$3.15	$1.40
Forward pricing, upper range (in dollars per MW)	$14.59	$9.83

FAIR_VALUE_MEASUREMENTS_Assets

FAIR VALUE MEASUREMENTS, Assets and Liabilities Classified as level 3 (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014
Changes in fair value of assets and liabilities classified as level 3 [Roll Forward]	'
Net derivative assets/(liabilities), Beginning balance	($142,786)
Unrealized gains and (losses), net	88,240
Net derivative assets/(liabilities), Ending balance	-54,546
Change in unrealized gains (losses), net relating to net derivative assets/(liabilities), still held as of September 30, 2014	$88,240

FAIR_VALUE_MEASUREMENTS_Regula

FAIR VALUE MEASUREMENTS, Regulatory Assets and Liabilities (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014
Change in regulatory asset/liability balances [Roll Forward]	'
Net regulatory assets/(liabilities), Beginning balance	$142,786
Unrealized (gains) and losses, net	-88,240
Net regulatory assets/(liabilities), Ending balance	$54,546

SEGMENT_INFORMATION_Details

SEGMENT INFORMATION (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013		Dec. 31, 2013
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating Revenues	$293,026,000		$316,478,000		$1,198,982,000		$1,183,591,000		'
Purchased power and gas	68,776,000		74,657,000		446,067,000		421,516,000		'
Operation and maintenance	95,251,000		89,810,000		290,828,000		273,539,000		'
Transmission wholesale	25,802,000		28,659,000		65,777,000		65,994,000		'
Depreciation and amortization	35,578,000		50,761,000		112,408,000		146,537,000		'
Taxes - other than income taxes	32,897,000		32,389,000		102,974,000		96,335,000		'
Acquisition-related expenses	570,000		0		6,090,000		0		'
Rate case disallowances	0		17,543,000		0		17,543,000		'
Operating Income	34,152,000		22,659,000		174,838,000		162,127,000		'
Other Income and (Deductions), net	3,487,000		5,153,000		-2,366,000		15,718,000		'
Interest Charges, net	23,641,000		22,399,000		70,322,000		69,533,000		'
Income from Equity Investments	3,492,000		3,930,000		10,398,000		11,590,000		'
Income (Loss) Before Income Taxes	17,490,000		9,343,000		112,548,000		119,902,000		'
Income Taxes	4,986,000		4,186,000		35,276,000		45,004,000		'
Net Income (Loss)	12,504,000		5,157,000		77,272,000		74,898,000		'
Less: Preferred Stock Dividends of Subsidiary, Noncontrolling Interests	6,000		13,000		-21,000		39,000		'
Net Income (Loss) attributable to UIL Holdings	12,498,000		5,144,000		77,293,000		74,859,000		'
Total Capital Expenditure	70,630,000	[1]	80,188,000	[1]	196,171,000		224,172,000		'
Total Assets	4,857,741,000		'		4,857,741,000		'		5,144,220,000
Net plant in service segregated by segment [Abstract]	'		'		'		'		'
Goodwill	266,205,000		'		266,205,000		'		266,205,000
Reporting Segments [Member] | Electric Distribution Reportable Segment [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating Revenues	134,289,000		151,369,000		397,384,000		421,959,000		'
Purchased power and gas	37,962,000		37,314,000		123,771,000		105,996,000		'
Operation and maintenance	42,819,000		43,387,000		135,282,000		132,919,000		'
Transmission wholesale	0		0		0		0		'
Depreciation and amortization	11,943,000		28,397,000		35,902,000		72,924,000		'
Taxes - other than income taxes	14,244,000		13,390,000		38,597,000		36,860,000		'
Acquisition-related expenses	0		'		0		'		'
Rate case disallowances	'		17,543,000		'		17,543,000		'
Operating Income	27,321,000		11,338,000		63,832,000		55,717,000		'
Other Income and (Deductions), net	2,877,000		3,534,000		9,503,000		10,687,000		'
Interest Charges, net	7,590,000		6,088,000		22,661,000		19,834,000		'
Income from Equity Investments	3,492,000		3,930,000		10,398,000		11,590,000		'
Income (Loss) Before Income Taxes	26,100,000		12,714,000		61,072,000		58,160,000		'
Income Taxes	8,173,000		5,607,000		18,015,000		24,464,000		'
Net Income (Loss)	17,927,000		7,107,000		43,057,000		33,696,000		'
Less: Preferred Stock Dividends of Subsidiary, Noncontrolling Interests	0		0		0		0		'
Net Income (Loss) attributable to UIL Holdings	17,927,000		7,107,000		43,057,000		33,696,000		'
Total Capital Expenditure	0	[1]	0	[1]	0	[1]	0	[1]	'
Total Assets	0	[2]	'		0	[2]	'		0	[2]
Reporting Segments [Member] | Electric Transmission Reportable Segment [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating Revenues	62,926,000		67,830,000		183,715,000		180,412,000		'
Purchased power and gas	0		0		0		0		'
Operation and maintenance	11,456,000		11,532,000		36,049,000		33,212,000		'
Transmission wholesale	25,802,000		28,659,000		65,777,000		65,994,000		'
Depreciation and amortization	4,208,000		4,152,000		12,635,000		12,123,000		'
Taxes - other than income taxes	10,441,000		10,466,000		26,832,000		25,260,000		'
Acquisition-related expenses	0		'		0		'		'
Rate case disallowances	'		0		'		0		'
Operating Income	11,019,000		13,021,000		42,422,000		43,823,000		'
Other Income and (Deductions), net	881,000		746,000		2,793,000		3,465,000		'
Interest Charges, net	3,375,000		2,763,000		9,832,000		9,104,000		'
Income from Equity Investments	0		0		0		0		'
Income (Loss) Before Income Taxes	8,525,000		11,004,000		35,383,000		38,184,000		'
Income Taxes	3,048,000		3,890,000		12,262,000		13,474,000		'
Net Income (Loss)	5,477,000		7,114,000		23,121,000		24,710,000		'
Less: Preferred Stock Dividends of Subsidiary, Noncontrolling Interests	0		0		0		0		'
Net Income (Loss) attributable to UIL Holdings	5,477,000		7,114,000		23,121,000		24,710,000		'
Total Capital Expenditure	0	[1]	0	[1]	0	[1]	0	[1]	'
Total Assets	0	[2]	'		0	[2]	'		0	[2]
Reporting Segments [Member] | Total Electric Reportable Segments [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating Revenues	197,215,000		219,199,000		581,009,000		602,371,000		'
Purchased power and gas	37,962,000		37,314,000		123,771,000		105,996,000		'
Operation and maintenance	54,275,000		54,919,000		171,331,000		166,131,000		'
Transmission wholesale	25,802,000		28,659,000		65,777,000		65,994,000		'
Depreciation and amortization	16,151,000		32,549,000		48,537,000		85,047,000		'
Taxes - other than income taxes	24,685,000		23,856,000		65,429,000		62,120,000		'
Acquisition-related expenses	0		'		0		'		'
Rate case disallowances	'		17,543,000		'		17,543,000		'
Operating Income	38,340,000		24,359,000		106,254,000		99,540,000		'
Other Income and (Deductions), net	3,758,000		4,280,000		12,296,000		14,152,000		'
Interest Charges, net	10,965,000		8,851,000		32,493,000		28,938,000		'
Income from Equity Investments	3,492,000		3,930,000		10,398,000		11,590,000		'
Income (Loss) Before Income Taxes	34,625,000		23,718,000		96,455,000		96,344,000		'
Income Taxes	11,221,000		9,497,000		30,277,000		37,938,000		'
Net Income (Loss)	23,404,000		14,221,000		66,178,000		58,406,000		'
Less: Preferred Stock Dividends of Subsidiary, Noncontrolling Interests	0		0		0		0		'
Net Income (Loss) attributable to UIL Holdings	23,404,000		14,221,000		66,178,000		58,406,000		'
Total Capital Expenditure	31,523,000	[1]	41,310,000	[1]	91,600,000	[1]	124,437,000	[1]	'
Total Assets	2,709,623,000	[2]	'		2,709,623,000	[2]	'		2,950,707,000	[2]
Reporting Segments [Member] | Gas Distribution Reportable Segment [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating Revenues	94,708,000		97,244,000		616,780,000		581,115,000		'
Purchased power and gas	30,504,000		37,343,000		321,986,000		315,520,000		'
Operation and maintenance	44,950,000		36,271,000		130,761,000		111,496,000		'
Transmission wholesale	0		0		0		0		'
Depreciation and amortization	16,477,000		17,202,000		55,994,000		58,515,000		'
Taxes - other than income taxes	9,082,000		8,410,000		37,080,000		33,769,000		'
Acquisition-related expenses	0		'		0		'		'
Rate case disallowances	'		0		'		0		'
Operating Income	-6,305,000		-1,982,000		70,959,000		61,815,000		'
Other Income and (Deductions), net	702,000		234,000		-587,000		-298,000		'
Interest Charges, net	7,116,000		7,507,000		21,320,000		22,415,000		'
Income from Equity Investments	0		0		0		0		'
Income (Loss) Before Income Taxes	-12,719,000		-9,255,000		49,052,000		39,102,000		'
Income Taxes	-6,229,000		-2,970,000		18,749,000		14,770,000		'
Net Income (Loss)	-6,490,000		-6,285,000		30,303,000		24,332,000		'
Less: Preferred Stock Dividends of Subsidiary, Noncontrolling Interests	6,000		13,000		-21,000		39,000		'
Net Income (Loss) attributable to UIL Holdings	-6,496,000		-6,298,000		30,324,000		24,293,000		'
Total Capital Expenditure	32,926,000	[1]	25,968,000	[1]	78,278,000	[1]	63,771,000	[1]	'
Total Assets	1,996,825,000	[3]	'		1,996,825,000	[3]	'		2,010,246,000	[3]
Net plant in service segregated by segment [Abstract]	'		'		'		'		'
Goodwill	266,200,000		'		266,200,000		'		266,200,000
Reporting Segments [Member] | Other [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating Revenues	1,103,000		35,000		1,103,000		105,000		'
Purchased power and gas	310,000		0		310,000		0		'
Operation and maintenance	-3,974,000		-1,380,000		-11,264,000		-4,088,000		'
Transmission wholesale	0		0		0		0		'
Depreciation and amortization	2,950,000		1,010,000		7,877,000		2,975,000		'
Taxes - other than income taxes	-870,000		123,000		465,000		446,000		'
Acquisition-related expenses	570,000		'		6,090,000		'		'
Rate case disallowances	'		0		'		0		'
Operating Income	2,117,000		282,000		-2,375,000		772,000		'
Other Income and (Deductions), net	-973,000		639,000		-14,075,000		1,864,000		'
Interest Charges, net	5,560,000		6,041,000		16,509,000		18,180,000		'
Income from Equity Investments	0		0		0		0		'
Income (Loss) Before Income Taxes	-4,416,000		-5,120,000		-32,959,000		-15,544,000		'
Income Taxes	-6,000		-2,341,000		-13,750,000		-7,704,000		'
Net Income (Loss)	-4,410,000		-2,779,000		-19,209,000		-7,840,000		'
Less: Preferred Stock Dividends of Subsidiary, Noncontrolling Interests	0		0		0		0		'
Net Income (Loss) attributable to UIL Holdings	-4,410,000		-2,779,000		-19,209,000		-7,840,000		'
Total Capital Expenditure	6,181,000	[1]	12,910,000	[1]	26,293,000	[1]	35,964,000	[1]	'
Total Assets	151,293,000		'		151,293,000		'		183,267,000
Reporting Segments [Member] | Distribution Segment [Member]	'		'		'		'		'
Net plant in service segregated by segment [Abstract]	'		'		'		'		'
Net plant in service	1,236,800,000		'		1,236,800,000		'		1,181,100,000
Reporting Segments [Member] | Transmission Segment [Member]	'		'		'		'		'
Net plant in service segregated by segment [Abstract]	'		'		'		'		'
Net plant in service	$658,200,000		'		$658,200,000		'		$656,000,000
[1]	Information for segmenting total capital expenditures between Distribution and Transmission is not available. Total Electric Distribution and Transmission capital expenditures are disclosed in the Total Electric Distribution and Transmission column.
[2]	Information for segmenting total assets between Distribution and Transmission is not available. Total Electric Distribution and Transmission assets are disclosed in the Total Electric and Distribution and Transmission column. Net plant in service is segregated by segment and, as of September 30, 2014, was $1,236.8 million and $658.2 million for Distribution and Transmission, respectively. As of December 31, 2013, net plant in service was $1,181.1 million and $656.0 million for Distribution and Transmission, respectively.
[3]	Includes $266.2 million of goodwill in the Gas Distribution segment as of September 30, 2014 and December 31, 2013.