EVERSOURCE ENERGY - Quarter Report: 2014 June (Form 10-Q)

Converted by EDGARwiz

[june2014form10q002.gif]

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q


T	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Quarterly Period Ended June 30, 2014
	OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to ____________


Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.

1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) 300 Cadwell Drive Springfield, Massachusetts 01104 Telephone: (413) 785-5871	04-2147929


0-00404	THE CONNECTICUT LIGHT AND POWER COMPANY (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone: (860) 665-5000	06-0303850


1-02301	NSTAR ELECTRIC COMPANY (a Massachusetts corporation) 800 Boylston Street Boston, Massachusetts 02199 Telephone: (617) 424-2000	04-1278810


1-6392	PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (a New Hampshire corporation) Energy Park 780 North Commercial Street Manchester, New Hampshire 03101-1134 Telephone: (603) 669-4000	02-0181050


0-7624	WESTERN MASSACHUSETTS ELECTRIC COMPANY (a Massachusetts corporation) 300 Cadwell Drive Springfield, Massachusetts 01104 Telephone: (413) 785-5871	04-1961130

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.


	Yes	No

	T	£

Indicate by check mark whether the registrants have submitted electronically and posted on its corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).


	Yes	No

	T	£

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):


	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer

Northeast Utilities	T	£	£
The Connecticut Light and Power Company	£	£	T
NSTAR Electric Company	£	£	T
Public Service Company of New Hampshire	£	£	T
Western Massachusetts Electric Company	£	£	T

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):


	Yes	No

Northeast Utilities	£	T
The Connecticut Light and Power Company	£	T
NSTAR Electric Company	£	T
Public Service Company of New Hampshire	£	T
Western Massachusetts Electric Company	£	T

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:


Company - Class of Stock	Outstanding as of July 31, 2014
Northeast Utilities Common shares, $5.00 par value	316,385,790 shares

The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares

NSTAR Electric Company Common stock, $1.00 par value	100 shares

Public Service Company of New Hampshire Common stock, $1.00 par value	301 shares

Western Massachusetts Electric Company Common stock, $25.00 par value	434,653 shares

Northeast Utilities holds all of the 6,035,205 shares, 100 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.

NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q, and each is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

GLOSSARY OF TERMS


The following is a glossary of abbreviations or acronyms that are found in this report:

CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:

CL&P	The Connecticut Light and Power Company
CYAPC	Connecticut Yankee Atomic Power Company
Hopkinton	Hopkinton LNG Corp., a wholly owned subsidiary of Yankee Energy System, Inc.
HWP	HWP Company, formerly the Holyoke Water Power Company
MYAPC	Maine Yankee Atomic Power Company
NGS	Northeast Generation Services Company
NPT	Northern Pass Transmission LLC
NSTAR	Parent Company of NSTAR Electric, NSTAR Gas and other subsidiaries (prior to the merger with NU)
NSTAR Electric	NSTAR Electric Company
NSTAR Electric & Gas	NSTAR Electric & Gas Corporation, a former Northeast Utilities service company (effective January 1, 2014 merged into NUSCO)
NSTAR Gas	NSTAR Gas Company
NU Enterprises	NU Enterprises, Inc., the parent company of NGS, Select Energy, Select Energy Contracting, Inc., E.S. Boulos Company and NSTAR Communications, Inc.
NU or the Company	Northeast Utilities and subsidiaries
NU parent and other companies	NU parent and other companies is comprised of NU parent, NUSCO and other subsidiaries, which primarily include NU Enterprises, HWP, RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company), and the consolidated operations of CYAPC and YAEC
NUSCO	Northeast Utilities Service Company (effective January 1, 2014 includes the operations of NSTAR Electric & Gas)
NUTV	NU Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc.
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's Regulated companies, comprised of the electric distribution and transmission businesses of CL&P, NSTAR Electric, PSNH, and WMECO, the natural gas distribution businesses of Yankee Gas and NSTAR Gas, the generation activities of PSNH and WMECO, and NPT
RRR	The Rocky River Realty Company
Select Energy	Select Energy, Inc.
WMECO	Western Massachusetts Electric Company
YAEC	Yankee Atomic Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Companies	CYAPC, YAEC and MYAPC
Yankee Gas	Yankee Gas Services Company
REGULATORS:
DEEP	Connecticut Department of Energy and Environmental Protection
DOE	U.S. Department of Energy
DOER	Massachusetts Department of Energy Resources
DPU	Massachusetts Department of Public Utilities
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
ISO-NE	ISO New England, Inc., the New England Independent System Operator
MA DEP	Massachusetts Department of Environmental Protection
NHPUC	New Hampshire Public Utilities Commission
PURA	Connecticut Public Utilities Regulatory Authority
SEC	U.S. Securities and Exchange Commission
SJC	Supreme Judicial Court of Massachusetts
OTHER:
AFUDC	Allowance For Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income/(Loss)
ARO	Asset Retirement Obligation
C&LM	Conservation and Load Management
CfD	Contract for Differences
Clean Air Project	The construction of a wet flue gas desulphurization system, known as "scrubber technology," to reduce mercury emissions of the Merrimack coal-fired generation station in Bow, New Hampshire
CO₂	Carbon dioxide
CPSL	Capital Projects Scheduling List
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES	Default Energy Service
ESOP	Employee Stock Ownership Plan
ESPP	Employee Share Purchase Plan
FERC ALJ	FERC Administrative Law Judge
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
GSC	Generation Service Charge
GSRP	Greater Springfield Reliability Project
GWh	Gigawatt-Hours
HG&E	Holyoke Gas and Electric, a municipal department of the City of Holyoke, MA
HQ	Hydro-Québec, a corporation wholly owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada
HVDC	High voltage direct current
Hydro Renewable Energy	Hydro Renewable Energy, Inc., a wholly owned subsidiary of Hydro-Québec
IPP	Independent Power Producers
ISO-NE Tariff	ISO-NE FERC Transmission, Markets and Services Tariff
kV	Kilovolt
kW	Kilowatt (equal to one thousand watts)
kWh	Kilowatt-Hours (the basic unit of electricity energy equal to one kilowatt of power supplied for one hour)
LNG	Liquefied natural gas
LOC	Letter of Credit
LRS	Supplier of last resort service
MGP	Manufactured Gas Plant
Millstone	Millstone Nuclear Generating station, made up of Millstone 1, Millstone 2, and Millstone 3. All three units were sold in March 2001.
MMBtu	One million British thermal units
Moody's	Moody's Investors Services, Inc.
MW	Megawatt
MWh	Megawatt-Hours
NEEWS	New England East-West Solution
Northern Pass	The high voltage direct current transmission line project from Canada into New Hampshire
NO_x	Nitrogen oxide
NU 2013 Form 10-K	The Northeast Utilities and Subsidiaries 2013 combined Annual Report on Form 10-K as filed with the SEC
PAM	Pension and PBOP Rate Adjustment Mechanism
PBOP	Postretirement Benefits Other Than Pension
PBOP Plan	Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits
PCRBs	Pollution Control Revenue Bonds
Pension Plan	Single uniform noncontributory defined benefit retirement plan
PPA	Pension Protection Act
RECs	Renewable Energy Certificates
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segment excluding the wholesale transmission segment
ROE	Return on Equity
RRB	Rate Reduction Bond or Rate Reduction Certificate
RSUs	Restricted share units
S&P	Standard & Poor's Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plans and non-qualified defined benefit retirement plans
Settlement Agreements	The comprehensive settlement agreements reached by NU and NSTAR with the Massachusetts Attorney General and the DOER on February 15, 2012 related to the merger of NU and NSTAR (Massachusetts settlement agreements) and the comprehensive settlement agreement reached by NU and NSTAR with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel on March 13, 2012 related to the merger of NU and NSTAR (Connecticut settlement agreement).
SIP	Simplified Incentive Plan
SO₂	Sulfur dioxide
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Service Agreement
UI	The United Illuminating Company

NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY

TABLE OF CONTENTS


	Page
PART I - FINANCIAL INFORMATION

ITEM 1 - Unaudited Condensed Consolidated Financial Statements for the Following Companies:
Northeast Utilities and Subsidiaries (Unaudited)
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Income	3
Condensed Consolidated Statements of Comprehensive Income	3
Condensed Consolidated Statements of Cash Flows	4

The Connecticut Light and Power Company (Unaudited)
Condensed Balance Sheets	5
Condensed Statements of Income	7
Condensed Statements of Comprehensive Income	7
Condensed Statements of Cash Flows	8

NSTAR Electric Company and Subsidiary (Unaudited)
Condensed Consolidated Balance Sheets	9
Condensed Consolidated Statements of Income	11
Condensed Consolidated Statements of Cash Flows	12

Public Service Company of New Hampshire and Subsidiary (Unaudited)
Condensed Consolidated Balance Sheets	13
Condensed Consolidated Statements of Inco me	15
Condensed Consolidated Statements of Comprehensive Income	15
Condensed Consolidated Statements of Cash Flows	16

Western Massachusetts Electric Company (Unaudited)
Condensed Balance Sheets	17
Condensed Statements of Income	19
Condensed Statements of Comprehensive Income	19
Condensed Statements of Cash Flows	20

Combined Notes to Condensed Consolidated Financial Statements (Unaudited)	21


ITEM 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations for the following companies:
Northeast Utilities and Subsidiaries	39
The Connecticut Light and Power Company	51
NSTAR Electric Company and Subsidiary	54
Public Service Company of New Hampshire and Subsidiary	56
Western Massachusetts Electric Company	58

ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk	60

ITEM 4 – Controls and Procedures	60

PART II – OTHER INFORMATION

ITEM 1 – Legal Proceedings	61

ITEM 1A – Risk Factors	61

ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds	61

ITEM 6 – Exhibits	62

SIGNATURES	64

iii


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


		June 30,		December 31,
(Thousands of Dollars)		2014		2013

ASSETS

Current Assets:
	Cash and Cash Equivalents	$	34,096	$	43,364
	Receivables, Net		807,510		765,391
	Unbilled Revenues		193,983		224,982
	Fuel, Materials and Supplies		281,721		303,233
	Regulatory Assets		467,156		535,791
	Marketable Securities		115,987		92,427
	Prepayments and Other Current Assets		168,022		121,861
Total Current Assets			2,068,475		2,087,049

Property, Plant and Equipment, Net			17,978,692		17,576,186

Deferred Debits and Other Assets:
	Regulatory Assets		3,339,457		3,758,694
	Goodwill		3,519,401		3,519,401
	Marketable Securities		513,986		488,515
	Other Long-Term Assets		370,434		365,692
Total Deferred Debits and Other Assets			7,743,278		8,132,302



Total Assets		$	27,790,445	$	27,795,537



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


			June 30,		December 31,
(Thousands of Dollars)			2014		2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable		$	905,000	$	1,093,000
	Long-Term Debt - Current Portion			395,583		533,346
	Accounts Payable			561,699		742,251
	Regulatory Liabilities			359,921		204,278
	Other Current Liabilities			580,605		702,776
Total Current Liabilities				2,802,808		3,275,651

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			4,270,050		4,029,026
	Regulatory Liabilities			503,955		502,984
	Derivative Liabilities			449,439		624,050
	Accrued Pension, SERP and PBOP			825,001		896,844
	Other Long-Term Liabilities			882,688		923,053
Total Deferred Credits and Other Liabilities				6,931,133		6,975,957

Capitalization:
	Long-Term Debt			8,147,129		7,776,833

	Noncontrolling Interest - Preferred Stock of Subsidiaries			155,568		155,568

	Equity:
	Common Shareholders' Equity:
		Common Shares		1,666,637		1,665,351
		Capital Surplus, Paid In		6,201,555		6,192,765
		Retained Earnings		2,241,025		2,125,980
		Accumulated Other Comprehensive Loss		(41,507)		(46,031)
		Treasury Stock		(313,903)		(326,537)
	Common Shareholders' Equity			9,753,807		9,611,528
Total Capitalization				18,056,504		17,543,929

Total Liabilities and Capitalization			$	27,790,445	$	27,795,537



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


				For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Thousands of Dollars, Except Share Information)				2014		2013		2014		2013

Operating Revenues				$	1,677,614	$	1,635,862	$	3,968,204	$	3,630,885

Operating Expenses:
	Purchased Power, Fuel and Transmission				624,211		488,302		1,602,362		1,236,111
	Operations and Maintenance				373,234		357,169		724,922		703,261
	Depreciation				152,207		159,553		303,014		314,530
	Amortization of Regulatory Assets/(Liabilities), Net				(3,542)		54,574		54,356		108,623
	Amortization of Rate Reduction Bonds				-		8,082		-		42,581
	Energy Efficiency Programs				102,711		94,142		241,536		199,913
	Taxes Other Than Income Taxes				134,803		123,464		280,335		256,345
			Total Operating Expenses		1,383,624		1,285,286		3,206,525		2,861,364
Operating Income					293,990		350,576		761,679		769,521

Interest Expense:
	Interest on Long-Term Debt				87,491		85,999		174,868		171,294
	Other Interest				5,004		851		7,603		(8,188)
		Interest Expense			92,495		86,850		182,471		163,106
Other Income, Net					5,526		4,944		7,194		12,710
Income Before Income Tax Expense					207,021		268,670		586,402		619,125
Income Tax Expense					77,774		95,606		219,319		216,093
Net Income					129,247		173,064		367,083		403,032
Net Income Attributable to Noncontrolling Interests					1,880		2,043		3,759		3,922
Net Income Attributable to Controlling Interest				$	127,367	$	171,021	$	363,324	$	399,110

Basic Earnings Per Common Share				$	0.40	$	0.54	$	1.15	$	1.27

Diluted Earnings Per Common Share				$	0.40	$	0.54	$	1.15	$	1.26

Dividends Declared Per Common Share				$	0.39	$	0.37	$	0.79	$	0.74

Weighted Average Common Shares Outstanding:
	Basic				315,950,510		315,154,130		315,742,511		315,141,956
	Diluted				317,112,801		315,962,619		317,002,461		315,982,578


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income				$	129,247	$	173,064	$	367,083	$	403,032
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments				510		514		1,019		1,030
	Changes in Unrealized Gains/(Losses) on Other Securities				218		(591)		458		(772)
	Changes in Funded Status of Pension, SERP and PBOP Benefit Plans				2,086		1,506		3,047		3,127

Other Comprehensive Income, Net of Tax					2,814		1,429		4,524		3,385
Comprehensive Income Attributable to Noncontrolling Interests					(1,880)		(2,043)		(3,759)		(3,922)
Comprehensive Income Attributable to Controlling Interest				$	130,181	$	172,450	$	367,848	$	402,495


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)



			For the Six Months Ended June 30,
(Thousands of Dollars)			2014		2013

Operating Activities:
	Net Income		$	367,083	$	403,032
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		303,014		314,530
		Deferred Income Taxes		133,149		256,294
		Pension, SERP and PBOP Expense		47,558		97,671
		Pension and PBOP Contributions		(40,640)		(122,826)
		Regulatory Over/(Under) Recoveries, Net		164,388		(4,793)
		Amortization of Regulatory Assets, Net		54,356		108,623
		Amortization of Rate Reduction Bonds		-		42,581
		Proceeds from DOE Damages Claim, Net		125,658		-
		Other		(9,359)		19,932
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(57,570)		(101,229)
		Fuel, Materials and Supplies		26,633		10,964
		Taxes Receivable/Accrued, Net		(62,900)		(58,350)
		Accounts Payable		(112,954)		(127,379)
		Other Current Assets and Liabilities, Net		(41,753)		(70,026)
Net Cash Flows Provided by Operating Activities				896,663		769,024

Investing Activities:
	Investments in Property, Plant and Equipment			(724,043)		(700,252)
	Proceeds from Sales of Marketable Securities			256,309		342,251
	Purchases of Marketable Securities			(257,168)		(424,096)
	Decrease in Special Deposits			2,894		65,121
	Other Investing Activities			579		(843)
Net Cash Flows Used in Investing Activities				(721,429)		(717,819)

Financing Activities:
	Cash Dividends on Common Shares			(237,161)		(232,068)
	Cash Dividends on Preferred Stock			(3,759)		(3,922)
	Decrease in Short-Term Debt			(213,000)		(720,500)
	Issuance of Long-Term Debt			650,000		1,350,000
	Retirements of Long-Term Debt			(376,650)		(360,635)
	Retirements of Rate Reduction Bonds			-		(82,139)
	Other Financing Activities			(3,932)		(11,634)
Net Cash Flows Used in Financing Activities				(184,502)		(60,898)
Net Decrease in Cash and Cash Equivalents				(9,268)		(9,693)
Cash and Cash Equivalents - Beginning of Period				43,364		45,748
Cash and Cash Equivalents - End of Period			$	34,096	$	36,055

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)


		June 30,		December 31,
(Thousands of Dollars)		2014		2013

ASSETS

Current Assets:
	Cash	$	10,486	$	7,237
	Receivables, Net		359,636		319,670
	Accounts Receivable from Affiliated Companies		85,134		13,777
	Unbilled Revenues		95,491		92,401
	Regulatory Assets		109,951		150,943
	Materials and Supplies		49,525		54,606
	Prepayments and Other Current Assets		56,238		53,082
Total Current Assets			766,461		691,716

Property, Plant and Equipment, Net			6,592,833		6,451,259

Deferred Debits and Other Assets:
	Regulatory Assets		1,392,529		1,663,147
	Other Long-Term Assets		196,935		174,380
Total Deferred Debits and Other Assets			1,589,464		1,837,527



Total Assets		$	8,948,758	$	8,980,502



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


THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)


			June 30,		December 31,
(Thousands of Dollars)			2014		2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to NU Parent		$	6,400	$	287,300
	Long-Term Debt - Current Portion			312,000		150,000
	Accounts Payable			189,171		201,047
	Accounts Payable to Affiliated Companies			44,031		56,531
	Obligations to Third Party Suppliers			59,312		73,914
	Accrued Taxes			52,900		37,186
	Regulatory Liabilities			143,457		93,961
	Derivative Liabilities			85,611		92,233
	Other Current Liabilities			94,204		97,530
Total Current Liabilities				987,086		1,089,702

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,610,662		1,510,586
	Regulatory Liabilities			86,677		93,757
	Derivative Liabilities			445,342		617,072
	Accrued Pension, SERP and PBOP			66,543		95,895
	Other Long-Term Liabilities			154,001		163,588
Total Deferred Credits and Other Liabilities				2,363,225		2,480,898

Capitalization:
	Long-Term Debt			2,679,591		2,591,208

	Preferred Stock Not Subject to Mandatory Redemption			116,200		116,200

	Common Stockholder's Equity:
		Common Stock		60,352		60,352
		Capital Surplus, Paid In		1,753,668		1,682,047
		Retained Earnings		989,786		961,482
		Accumulated Other Comprehensive Loss		(1,150)		(1,387)
	Common Stockholder's Equity			2,802,656		2,702,494
Total Capitalization				5,598,447		5,409,902

Total Liabilities and Capitalization			$	8,948,758	$	8,980,502



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


THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)


			For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Thousands of Dollars)			2014		2013			2014		2013

Operating Revenues			$	587,324	$	569,329	$	1,321,938	$	1,193,425

Operating Expenses:
	Purchased Power and Transmission			199,785		184,854		481,165		414,113
	Operations and Maintenance			131,762		123,760		241,276		232,655
	Depreciation			46,581		45,122		92,712		87,570
	Amortization of Regulatory Assets, Net			19,615		463		49,546		11,249
	Energy Efficiency Programs			35,296		20,854		77,991		43,668
	Taxes Other Than Income Taxes			62,159		57,506		129,111		117,697
		Total Operating Expenses		495,198		432,559		1,071,801		906,952
Operating Income				92,126		136,770		250,137		286,473

Interest Expense:
	Interest on Long-Term Debt			34,639		32,683		67,548		65,318
	Other Interest			2,831		1,301		4,165		(1,640)
		Interest Expense		37,470		33,984		71,713		63,678
Other Income, Net				3,130		2,897		4,202		7,084
Income Before Income Tax Expense				57,786		105,683		182,626		229,879
Income Tax Expense				20,401		37,826		65,942		77,014
Net Income			$	37,385	$	67,857	$	116,684	$	152,865



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





CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income			$	37,385	$	67,857	$	116,684	$	152,865
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			111		111		222		222
	Changes in Unrealized Gains/(Losses) on Other Securities			7		(20)		15		(26)
Other Comprehensive Income, Net of Tax				118		91		237		196
Comprehensive Income			$	37,503	$	67,948	$	116,921	$	153,061



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


THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)


	For the Six Months Ended June 30,
(Thousands of Dollars)	2014	2013


Operating Activities:
	Net Income		$	116,684	$	152,865
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:			92,712		87,570
		Depreciation
		Deferred Income Taxes		43,253		99,045
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		5,973		13,826
		Regulatory Over/(Under) Recoveries, Net		18,156		(36,902)
		Amortization of Regulatory Assets, Net		49,546		11,249
		Proceeds from DOE Damages Claim		65,370		-
		Other		(3,428)		(13,476)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(129,209)		(33,976)
		Taxes Receivable/Accrued, Net		27,679		(14,081)
		Accounts Payable		(26,995)		(95,487)
		Other Current Assets and Liabilities, Net		15,705		7,548
Net Cash Flows Provided by Operating Activities				275,446		178,181

Investing Activities:
	Investments in Property, Plant and Equipment			(221,365)		(184,875)
	Other Investing Activities			1,575		884
Net Cash Flows Used in Investing Activities				(219,790)		(183,991)

Financing Activities:
	Cash Dividends on Common Stock			(85,600)		(76,000)
	Cash Dividends on Preferred Stock			(2,779)		(2,779)
	Issuance of Long Term Debt			250,000		400,000
	Decrease in Notes Payable to NU Parent			(280,900)		(215,800)
	Capital Contribution from NU Parent			70,000		-
	Decrease in Short-Term Debt			-		(89,000)
	Other Financing Activities			(3,128)		(6,345)
Net Cash Flows (Used in)/Provided by Financing Activities				(52,407)		10,076
Net Increase in Cash				3,249		4,266
Cash - Beginning of Period				7,237		1
Cash - End of Period			$	10,486	$	4,267

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


NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


		June 30,		December 31,
(Thousands of Dollars)		2014		2013

ASSETS

Current Assets:
	Cash and Cash Equivalents	$	12,975	$	8,021
	Receivables, Net		230,039		209,711
	Accounts Receivable from Affiliated Companies		-		27,264
	Unbilled Revenues		40,514		41,368
	Materials and Supplies		51,635		44,236
	Regulatory Assets		178,640		204,144
	Prepayments and Other Current Assets		1,012		36,710
Total Current Assets			514,815		571,454

Property, Plant and Equipment, Net			5,147,239		5,043,887

Deferred Debits and Other Assets:
	Regulatory Assets		1,020,990		1,235,156
	Other Long-Term Assets		64,963		60,624
Total Deferred Debits and Other Assets			1,085,953		1,295,780



Total Assets		$	6,748,007	$	6,911,121




The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


			June 30,		December 31,
(Thousands of Dollars)			2014		2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable		$	194,500	$	103,500
	Long-Term Debt - Current Portion			4,700		301,650
	Accounts Payable			150,615		207,559
	Accounts Payable to Affiliated Companies			69,949		75,707
	Accrued Taxes			44,308		7,946
	Accumulated Deferred Income Taxes			54,434		50,128
	Regulatory Liabilities			89,161		53,958
	Other Current Liabilities			109,048		110,464
Total Current Liabilities				716,715		910,912

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,377,432		1,466,835
	Regulatory Liabilities			260,480		253,108
	Accrued Pension, SERP and PBOP			150,151		118,010
	Payable to Affiliated Companies			-		64,172
	Other Long-Term Liabilities			129,837		142,214
Total Deferred Credits and Other Liabilities				1,917,900		2,044,339

Capitalization:
	Long-Term Debt			1,792,702		1,499,417

	Preferred Stock Not Subject to Mandatory Redemption			43,000		43,000

	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		992,625		992,625
		Retained Earnings		1,285,065		1,420,828
	Common Stockholder's Equity			2,277,690		2,413,453
Total Capitalization				4,113,392		3,955,870

Total Liabilities and Capitalization			$	6,748,007	$	6,911,121



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


			For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Thousands of Dollars)			2014		2013			2014		2013

Operating Revenues			$	561,513	$	570,420	$	1,227,701	$	1,162,677

Operating Expenses:
	Purchased Power and Transmission			242,907		189,843		561,989		403,896
	Operations and Maintenance			78,981		87,891		164,905		180,192
	Depreciation			46,915		45,441		93,540		90,882
	Amortization of Regulatory Assets/(Liabilities), Net			(1,517)		53,554		14,147		100,548
	Amortization of Rate Reduction Bonds			-		-		-		15,054
	Energy Efficiency Programs			40,255		50,679		88,584		102,382
	Taxes Other Than Income Taxes			32,458		30,491		64,610		62,665
		Total Operating Expenses		439,999		457,899		987,775		955,619
Operating Income				121,514		112,521		239,926		207,058

Interest Expense:
	Interest on Long-Term Debt			19,732		19,809		40,489		39,401
	Other Interest			960		(2,620)		1,263		(6,288)
		Interest Expense		20,692		17,189		41,752		33,113
Other Income/(Loss), Net				(246)		375		(277)		1,149
Income Before Income Tax Expense				100,576		95,707		197,897		175,094
Income Tax Expense				40,447		37,676		79,681		68,941
Net Income			$	60,129	$	58,031	$	118,216	$	106,153



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	For the Six Months Ended June 30,
(Thousands of Dollars)	2014	2013


Operating Activities:
	Net Income		$	118,216	$	106,153
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities
		Depreciation		93,540		90,882
		Deferred Income Taxes		(21,724)		28,750
		Pension and PBOP Expense, Net of Contributions		(8,281)		(5,139)
		Regulatory Over/(Under) Recoveries, Net		63,955		(33,901)
		Amortization of Regulatory Assets, Net		14,147		100,548
		Amortization of Rate Reduction Bonds		-		15,054
		Proceeds from DOE Damages Claim		29,113		-
		Bad Debt Expense		12,272		11,307
		Other		(29,142)		(47,574)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(31,746)		(60,174)
		Materials and Supplies		(7,399)		3,294
		Taxes Receivable/Accrued, Net		65,692		(39,813)
		Accounts Payable		(21,511)		(8,686)
		Accounts Receivable from/Payable to Affiliates, Net		107,363		(57,369)
		Other Current Assets and Liabilities, Net		3,158		(11,702)
Net Cash Flows Provided by Operating Activities				387,653		91,630

Investing Activities:
	Investments in Property, Plant and Equipment			(213,508)		(207,380)
	Decrease in Special Deposits			581		38,429
	Other Investing Activities			(5)		77
Net Cash Flows Used in Investing Activities				(212,932)		(168,874)

Financing Activities:
	Cash Dividends on Common Stock			(253,000)		(56,000)
	Cash Dividends on Preferred Stock			(980)		(1,143)
	Increase/(Decrease) in Notes Payable			91,000		(23,000)
	Issuance of Long-Term Debt			300,000		200,000
	Retirements of Long-Term Debt			(301,650)		(1,650)
	Retirements of Rate Reduction Bonds			-		(43,493)
	Other Financing Activities			(5,137)		-
Net Cash Flows (Used in)/Provided by Financing Activities				(169,767)		74,714
Net Increase/(Decrease) in Cash and Cash Equivalents				4,954		(2,530)
Cash and Cash Equivalents - Beginning of Period				8,021		13,695
Cash and Cash Equivalents - End of Period			$	12,975	$	11,165



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


		June 30,		December 31,
(Thousands of Dollars)		2014		2013

ASSETS

Current Assets:
	Cash	$	337	$	130
	Receivables, Net		69,646		76,331
	Accounts Receivable from Affiliated Companies		54		90
	Unbilled Revenues		36,971		38,344
	Taxes Receivable		45,957		2,180
	Fuel, Materials and Supplies		120,723		128,736
	Regulatory Assets		95,270		92,194
	Prepayments and Other Current Assets		21,770		21,920
Total Current Assets			390,728		359,925

Property, Plant and Equipment, Net			2,519,921		2,467,556

Deferred Debits and Other Assets:
	Regulatory Assets		187,592		219,346
	Other Long-Term Assets		53,779		39,891
Total Deferred Debits and Other Assets			241,371		259,237



Total Assets		$	3,152,020	$	3,086,718



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


			June 30,		December 31,
(Thousands of Dollars)			2014		2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to NU Parent		$	95,000	$	86,500
	Long-Term Debt - Current Portion			50,000		50,000
	Accounts Payable			58,910		82,920
	Accounts Payable to Affiliated Companies			18,760		22,040
	Regulatory Liabilities			36,627		20,643
	Accumulated Deferred Income Taxes			25,397		28,596
	Other Current Liabilities			35,440		51,729
Total Current Liabilities				320,134		342,428

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			563,291		500,166
	Regulatory Liabilities			50,843		51,723
	Accrued SERP and PBOP			15,055		15,272
	Other Long-Term Liabilities			46,598		46,247
Total Deferred Credits and Other Liabilities				675,787		613,408

Capitalization:
	Long-Term Debt			999,157		999,006

	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		702,652		701,911
		Retained Earnings		462,233		438,515
		Accumulated Other Comprehensive Loss		(7,943)		(8,550)
	Common Stockholder's Equity			1,156,942		1,131,876
Total Capitalization				2,156,099		2,130,882

Total Liabilities and Capitalization			$	3,152,020	$	3,086,718



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


			For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Thousands of Dollars)			2014				2013				2014						2013

Operating Revenues			$		211,626		$		216,113		$		511,458		$		489,942

Operating Expenses:
	Purchased Power, Fuel and Transmission				68,349				50,073				183,595				151,097
	Operations and Maintenance				70,249				62,400				132,462				122,129
	Depreciation				24,464				22,947				48,679				45,515
	Amortization of Regulatory Assets/(Liabilities), Net				(20,393)				1,081				(7,831)				(1,969)
	Amortization of Rate Reduction Bonds				-				4,991				-				19,748
	Energy Efficiency Programs				3,292				3,376				7,131				7,046
	Taxes Other Than Income Taxes				16,635				16,918				34,348				33,932
		Total Operating Expenses			162,596				161,786				398,384				377,498
Operating Income					49,030				54,327				113,074				112,444

Interest Expense:
	Interest on Long-Term Debt				11,390				10,811				22,916				22,606
	Other Interest				(391)				337				55				709
		Interest Expense			10,999				11,148				22,971				23,315
Other Income, Net					946				632				1,212				1,662
Income Before Income Tax Expense					38,977				43,811				91,315				90,791
Income Tax Expense					14,897				16,617				34,597				34,602
Net Income			$		24,080		$		27,194		$		56,718		$		56,189



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.





CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income			$	24,080		$		27,194		$		56,718		$		56,189
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			291				291				581				582
	Changes in Unrealized Gains/(Losses) on Other Securities			12				(34)				26				(45)
	Changes in Funded Status of Pension, SERP and PBOP Benefit Plans			-				-				-				(3)
Other Comprehensive Income, Net of Tax				303				257				607				534
Comprehensive Income			$	24,383		$		27,451		$		57,325		$		56,723



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


			For the Six Months Ended June 30,
(Thousands of Dollars)			2014		2013

Operating Activities:
	Net Income		$	56,718	$	56,189
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		48,679		45,515
		Deferred Income Taxes		61,093		25,450
		Pension, SERP and PBOP Expense		3,249		14,228
		Pension and PBOP Contributions		(833)		(45,721)
		Regulatory Overrecoveries, Net		18,849		4,844
		Amortization of Regulatory Liabilities, Net		(7,831)		(1,969)
		Amortization of Rate Reduction Bonds		-		19,748
		Proceeds from DOE Damages Claim		13,103		-
		Other		4,386		3,123
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		3,500		597
		Fuel, Materials and Supplies		8,013		(13,289)
		Taxes Receivable/Accrued, Net		(55,243)		21,584
		Accounts Payable		(7,146)		26,159
		Other Current Assets and Liabilities, Net		(4,166)		(17,743)
Net Cash Flows Provided by Operating Activities				142,371		138,715

Investing Activities:
	Investments in Property, Plant and Equipment			(117,387)		(109,565)
	(Increase)/Decrease in Special Deposits			(45)		22,039
	Other Investing Activities			(56)		(13)
Net Cash Flows Used in Investing Activities				(117,488)		(87,539)

Financing Activities:
	Cash Dividends on Common Stock			(33,000)		(34,000)
	Increase in Notes Payable to NU Parent			8,500		118,900
	Retirements of Long-Term Debt			-		(108,985)
	Retirements of Rate Reduction Bonds			-		(29,294)
	Other Financing Activities			(176)		(225)
Net Cash Flows Used in Financing Activities				(24,676)		(53,604)
Net Increase/(Decrease) in Cash				207		(2,428)
Cash - Beginning of Period				130		2,493
Cash - End of Period			$	337	$	65



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)


		June 30,		December 31,
(Thousands of Dollars)		2014		2013

ASSETS

Current Assets:
	Cash	$	1,709	$	-
	Receivables, Net		49,404		49,018
	Accounts Receivable from Affiliated Companies		4,445		47,607
	Unbilled Revenues		15,617		16,562
	Taxes Receivable		15,228		432
	Regulatory Assets		36,251		43,024
	Marketable Securities		19,408		26,628
	Prepayments and Other Current Assets		10,730		10,479
Total Current Assets			152,792		193,750

Property, Plant and Equipment, Net			1,418,673		1,381,060

Deferred Debits and Other Assets:
	Regulatory Assets		120,303		146,088
	Marketable Securities		38,640		31,243
	Other Long-Term Assets		50,438		40,679
Total Deferred Debits and Other Assets			209,381		218,010



Total Assets		$	1,780,846	$	1,792,820



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


WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)


			June 30,		December 31,
(Thousands of Dollars)			2014		2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to NU Parent		$	15,900	$	-
	Accounts Payable			28,502		62,961
	Accounts Payable to Affiliated Companies			7,533		9,230
	Accrued Interest			7,524		7,525
	Regulatory Liabilities			44,745		19,858
	Accumulated Deferred Income Taxes			57		13,098
	Counterparty Deposits			188		7,688
	Other Current Liabilities			16,518		20,629
Total Current Liabilities				120,967		140,989

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			423,013		396,933
	Regulatory Liabilities			10,317		13,873
	Accrued SERP and PBOP			2,805		3,911
	Other Long-Term Liabilities			39,121		28,619
Total Deferred Credits and Other Liabilities				475,256		443,336

Capitalization:
	Long-Term Debt			628,932		629,389

	Common Stockholder's Equity:
		Common Stock		10,866		10,866
		Capital Surplus, Paid In		391,035		390,743
		Retained Earnings		157,134		181,014
		Accumulated Other Comprehensive Loss		(3,344)		(3,517)
	Common Stockholder's Equity			555,691		579,106
Total Capitalization				1,184,623		1,208,495

Total Liabilities and Capitalization			$	1,780,846	$	1,792,820



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


WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)


			For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Thousands of Dollars)			2014		2013		2014		2013

Operating Revenues			$	108,289	$	115,015	$	245,698	$	239,968

Operating Expenses:
	Purchased Power and Transmission			37,619		32,254		87,050		72,298
	Operations and Maintenance			23,686		23,136		46,265		44,064
	Depreciation			10,317		9,310		20,638		18,280
	Amortization of Regulatory Assets, Net			343		685		741		814
	Amortization of Rate Reduction Bonds			-		3,091		-		7,780
	Energy Efficiency Programs			10,249		7,925		22,114		16,240
	Taxes Other Than Income Taxes			8,396		6,206		16,479		12,494
		Total Operating Expenses		90,610		82,607		193,287		171,970
Operating Income				17,679		32,408		52,411		67,998

Interest Expense:
	Interest on Long-Term Debt			6,104		6,078		12,165		12,032
	Other Interest			603		198		188		537
		Interest Expense		6,707		6,276		12,353		12,569
Other Income, Net				594		419		1,168		1,423
Income Before Income Tax Expense				11,566		26,551		41,226		56,852
Income Tax Expense				4,548		10,137		16,106		21,836
Net Income			$	7,018	$	16,414	$	25,120	$	35,016



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





CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income			$	7,018	$	16,414	$	25,120	$	35,016
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			84		84		169		169
	Changes in Unrealized Gains/(Losses) on Other Securities			2		(6)		4		(8)
Other Comprehensive Income, Net of Tax				86		78		173		161
Comprehensive Income			$	7,104	$	16,492	$	25,293	$	35,177



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


WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)


			For the Six Months Ended June 30,
(Thousands of Dollars)			2014		2013

Operating Activities:
	Net Income		$	25,120	$	35,016
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		20,638		18,280
		Deferred Income Taxes		15,234		33,317
		Regulatory Over/(Under) Recoveries, Net		28,115		(5,094)
		Amortization of Regulatory Assets, Net		741		814
		Amortization of Rate Reduction Bonds		-		7,780
		Proceeds from DOE Damages Claim		18,073		-
		Other		1,462		572
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		44,859		(8,681)
		Taxes Receivable/Accrued, Net		(19,555)		21,081
		Accounts Payable		(26,494)		21,389
		Other Current Assets and Liabilities, Net		(11,587)		(5,166)
Net Cash Flows Provided by Operating Activities				96,606		119,308

Investing Activities:
	Investments in Property, Plant and Equipment			(61,470)		(96,051)
	Proceeds from Sales of Marketable Securities			44,449		41,604
	Purchases of Marketable Securities			(44,754)		(41,961)
	Other Investing Activities			-		4,601
Net Cash Flows Used in Investing Activities				(61,775)		(91,807)

Financing Activities:
	Cash Dividends on Common Stock			(49,000)		(20,000)
	Increase in Notes Payable to NU Parent			15,900		3,300
	Retirement of Rate Reduction Bonds			-		(9,352)
	Other Financing Activities			(22)		(31)
Net Cash Flows Used in Financing Activities				(33,122)		(26,083)
Net Increase in Cash				1,709		1,418
Cash - Beginning of Period				-		1
Cash - End of Period			$	1,709	$	1,419


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

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout the combined notes to the unaudited condensed consolidated financial statements.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

NU is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business. NU's wholly owned regulated utility subsidiaries consist of CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. NU provides energy delivery service to approximately 3.6 million electric and natural gas customers through these six regulated utilities in Connecticut, Massachusetts and New Hampshire.

The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."

The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q, the first quarter 2014 combined Quarterly Report on Form 10-Q and the 2013 combined Annual Report on Form 10-K of NU, CL&P, NSTAR Electric, PSNH and WMECO, which were filed with the SEC. The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's, CL&P's, NSTAR Electric's, PSNH's and WMECO's financial position as of June 30, 2014 and December 31, 2013, the results of operations and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the cash flows for the six months ended June 30, 2014 and 2013. The results of operations and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the cash flows for the six months ended June 30, 2014 and 2013 are not necessarily indicative of the results expected for a full year. The demand for electricity and natural gas is affected by weather conditions, economic conditions, and consumer conservation (including company-sponsored energy efficiency programs). Electric energy sales and revenues are typically higher in the winter and summer months than in the spring and fall months. Natural gas sales and revenues are typically higher in the winter months than during other periods of the year.

NU consolidates CYAPC and YAEC as CL&P's, NSTAR Electric's, PSNH's and WMECO's combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation of the NU financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, the investments in CYAPC and YAEC continue to be accounted for under the equity method.

NU's utility subsidiaries are subject to the application of accounting guidance for entities with rate-regulated operations that considers the effect of regulation resulting from differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. NU's utility subsidiaries' energy delivery business is subject to rate-regulation that is based on cost recovery and meets the criteria for application of rate-regulated accounting. See Note 2, "Regulatory Accounting," for further information.

Certain reclassifications of prior period data were made in the accompanying balance sheets for NU, CL&P, NSTAR Electric and PSNH, and in the statements of income for NU, NSTAR Electric, PSNH and WMECO. These reclassifications were made to conform to the current period presentation.

Accounting Standards

Recently Adopted Accounting Standards: On January 1, 2014, as required, NU prospectively adopted the Financial Accounting Standards Board's (FASB) final Accounting Standards Updates (ASU) that required presentation of certain unrecognized tax benefits as reductions to deferred tax assets. Implementation of this guidance had an immaterial impact on the balance sheets and no impact on the results of operations or cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO.

Accounting Standards Issued but not Yet Adopted: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, effective January 1, 2017, which amends existing revenue recognition guidance and is required to be applied retrospectively (either to each reporting period presented or cumulatively at the date of initial application). Management is reviewing the requirements of the new ASU, however the ASU's impact is not expected to have a material impact on the financial statements of NU, CL&P, NSTAR Electric, PSNH and WMECO.

Provision for Uncollectible Accounts

NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at estimated net realizable value by maintaining a provision for uncollectible accounts. This provision is determined based upon a variety of factors, including the application of an estimated uncollectible percentage to each receivable aging category. The estimate is based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management continuously assesses the collectibility of receivables, and adjusts collectibility estimates based on actual experience. Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible. The provision for uncollectible accounts, which is included in Receivables, Net on the balance sheets, was as follows:


(Millions of Dollars)	As of June 30, 2014		As of December 31, 2013
NU	$	197.4	$	171.3
CL&P		91.8		82.0
NSTAR Electric		44.4		41.7
PSNH		9.2		7.4
WMECO		12.9		10.0

Fair Value Measurements

Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal) and to the marketable securities held in trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of pension and PBOP plans and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.

Fair Value Hierarchy: In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:

Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.

Determination of Fair Value: The valuation techniques and inputs used in NU's fair value measurements are described in Note 4, "Derivative Instruments," Note 5, "Marketable Securities," and Note 9, "Fair Value of Financial Instruments," to the financial statements.

Other Income, Net

Items included within Other Income, Net on the statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds, and equity in earnings. Investment income/(loss) primarily relates to debt and equity securities held in trust. For further information, see Note 5, "Marketable Securities," to the financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, equity in earnings relate to investments in CYAPC, YAEC and MYAPC as well as NSTAR Electric's investment in two regional transmission companies, which are all accounted for on the equity method. On an NU consolidated basis, equity in earnings relate to the investment in MYAPC and NU's investment in two regional transmission companies.

Other Taxes

Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the statements of income as follows:


	For the Three Months Ended				For the Six Months Ended
(Millions of Dollars)	June 30, 2014		June 30, 2013		June 30, 2014		June 30, 2013
NU	$	35.2	$	33.0	$	79.6	$	71.4
CL&P		30.9		29.8		66.5		61.8

Certain sales taxes are also collected by NU's companies that serve customers in Connecticut and Massachusetts as agents for state and local governments and are recorded on a net basis with no impact on the statements of income.


G. Supplemental Cash Flow Information
Non-cash investing activities include plant additions included in Accounts Payable as follows:

(Millions of Dollars)	As of June 30, 2014		As of June 30, 2013
NU	$	125.5	$	109.5
CL&P		54.0		28.3
NSTAR Electric		21.6		33.4
PSNH		14.8		15.5
WMECO		9.9		17.0

In the first half of 2014, as a result of awards issued to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," NU recognized total proceeds of $125.7 million, which were net of $80.6 million in proceeds CY and YAEC returned to non-affiliated member companies.

Severance Benefits

NU recorded severance benefit expenses of $1.4 million and $5.7 million associated with the partial outsourcing of information technology functions and ongoing post-merger integration for the three and six months ended June 30, 2014, respectively. As of June 30, 2014 and December 31, 2013, the severance accrual totaled $9.3 million and $14.7 million, respectively, and was included in Other Current Liabilities on the balance sheets.

REGULATORY ACCOUNTING

The rates charged to the customers of NU's Regulated companies are designed to collect each company's costs to provide service, including a return on investment. Therefore, the accounting policies of the Regulated companies follow the application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process.

Management believes it is probable that each of the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to any of the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered from customers in future rates, the costs would be charged to net income in the period in which the determination is made.

Regulatory Assets: The components of regulatory assets are as follows:


	As of June 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Benefit Costs	$	1,146.7	$	1,240.2
Derivative Liabilities		431.4		638.0
Income Taxes, Net		631.8		626.2
Storm Restoration Costs		503.9		589.6
Goodwill-related		515.7		525.9
Regulatory Tracker Mechanisms		275.1		323.4
Contractual Obligations - Yankee Companies		128.4		154.2
Buy Out Agreements for Power Contracts		56.7		70.2
Other Regulatory Assets		117.0		126.8
Total Regulatory Assets		3,806.7		4,294.5
Less: Current Portion		467.2		535.8
Total Long-Term Regulatory Assets	$	3,339.5	$	3,758.7


	As of June 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Benefit Costs	$	251.9	$	323.4	$	81.6	$	46.2	$	297.7	$	496.7	$	100.6	$	57.3
Derivative Liabilities		424.6		6.3		-		-		630.4		7.7		-		-
Income Taxes, Net		426.2		81.4		38.0		40.8		415.5		84.0		40.3		43.7
Storm Restoration Costs		328.0		107.2		34.7		34.0		397.8		109.3		43.7		38.8
Goodwill-related		-		442.8		-		-		-		451.5		-		-
Regulatory Tracker Mechanisms		8.1		131.8		87.9		20.7		8.0		169.5		83.3		32.6
Buy Out Agreements for Power Contracts		-		52.0		4.7		-		-		64.7		5.5		-
Other Regulatory Assets		63.7		54.7		36.0		14.9		64.6		55.9		38.1		16.7
Total Regulatory Assets		1,502.5		1,199.6		282.9		156.6		1,814.0		1,439.3		311.5		189.1
Less: Current Portion		110.0		178.6		95.3		36.3		150.9		204.1		92.2		43.0
Total Long-Term Regulatory Assets	$	1,392.5	$	1,021.0	$	187.6	$	120.3	$	1,663.1	$	1,235.2	$	219.3	$	146.1

Benefit Costs: For information related to the Regulated companies' pension and other postretirement benefits, see Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions."

Storm Restoration Costs: On March 12, 2014, the PURA approved recovery of $365 million of deferred storm restoration costs associated with five major storms that occurred in 2011 and 2012. CL&P will recover the $365 million with carrying charges in its distribution rates over a six-year period beginning December 1, 2014. On June 17, 2014, the PURA ordered CL&P to use the DOE Phase II Damages proceeds of $65.4 million to offset the $365 million in 2011 and 2012 deferred storm restoration costs, which are reflected in the deferred storm restoration costs regulatory asset.

For further information on the DOE Phase II Damages proceeds received from the Yankee Companies, see Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.

Regulatory Costs in Other Long-Term Assets: The Regulated companies had $64.5 million ($3.4 million for CL&P, $33.9 million for NSTAR Electric, and $12 million for WMECO) and $65.1 million ($7.3 million for CL&P, $33.4 million for NSTAR Electric, and $10.1 million for WMECO) of additional regulatory costs as of June 30, 2014 and December 31, 2013, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs for which recovery has not yet been specifically approved by the applicable regulatory agency. However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates.

Regulatory Liabilities: The components of regulatory liabilities are as follows:


	As of June 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Cost of Removal	$	435.3	$	435.1
Regulatory Tracker Mechanisms		305.2		151.2
AFUDC - Transmission		67.4		68.1
Other Regulatory Liabilities		56.0		52.9
Total Regulatory Liabilities		863.9		707.3
Less: Current Portion		359.9		204.3
Total Long-Term Regulatory Liabilities	$	504.0	$	503.0


	As of June 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Cost of Removal	$	22.8	$	255.7	$	48.7	$	-	$	29.1	$	250.0	$	49.7	$	-
Regulatory Tracker Mechanisms		143.2		60.2		34.8		45.1		95.6		21.9		21.6		21.1
AFUDC - Transmission		54.2		4.0		-		9.2		54.7		4.1		-		9.3
Other Regulatory Liabilities		10.0		29.8		3.9		0.7		8.4		31.1		1.0		3.4
Total Regulatory Liabilities		230.2		349.7		87.4		55.0		187.8		307.1		72.3		33.8
Less: Current Portion		143.5		89.2		36.6		44.7		94.0		54.0		20.6		19.9
Total Long-Term Regulatory Liabilities	$	86.7	$	260.5	$	50.8	$	10.3	$	93.8	$	253.1	$	51.7	$	13.9

As a result of two FERC orders issued on June 19, 2014 in the pending base ROE complaint proceedings described in Note 8E, "Commitments and Contingencies – FERC Base ROE Complaints," in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings. The aggregate pre-tax charge totaled $54.7 million at NU, which represented reserves of $31.4 million at CL&P, $10.3 million at NSTAR Electric, $3.8 million at PSNH and $9.2 million at WMECO. As of June 30, 2014, the cumulative reserves totaled $79.3 million at NU, $44.7 million at CL&P, $16.2 million at NSTAR Electric, $6.2 million at PSNH and $12.2 million at WMECO. As of December 31, 2013, as a result of the FERC ALJ initial decision in the third quarter of 2013, the Company had an aggregate pre-tax reserve of $24.6 million at NU, which represented reserves of $13.3 million at CL&P, $5.9 million at NSTAR Electric, $2.4 million at PSNH and $3 million at WMECO. These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of operating revenues.

As a result of awards issued to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," the Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, effective June 1, 2014. CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each electric subsidiary's respective regulatory tracker mechanisms.

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

The following tables summarize the investments in utility property, plant and equipment by asset category:


		As of June 30, 2014		As of December 31, 2013
(Millions of Dollars)		NU		NU
Distribution - Electric		$	12,145.0	$	11,950.2
Distribution - Natural Gas			2,467.4		2,425.9
Transmission			6,508.0		6,412.5
Generation			1,167.9		1,152.3
Electric and Natural Gas Utility			22,288.3		21,940.9
Other⁽¹⁾			506.5		508.7
Property, Plant and Equipment, Gross			22,794.8		22,449.6
Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(5,575.8)		(5,387.0)
	Other		(207.7)		(196.2)
Total Accumulated Depreciation			(5,783.5)		(5,583.2)
Property, Plant and Equipment, Net			17,011.3		16,866.4
Construction Work in Progress			967.4		709.8
Total Property, Plant and Equipment, Net		$	17,978.7	$	17,576.2

⁽¹⁾

These assets represent unregulated property and are primarily comprised of building improvements, computer software, hardware and equipment and telecommunications assets at NU's unregulated companies.


	As of June 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Distribution	$	5,035.2	$	4,754.4	$	1,629.1	$	766.3	$	4,930.7	$	4,694.7	$	1,608.2	$	756.6
Transmission		3,108.1		1,798.9		713.5		841.1		3,071.9		1,772.3		695.7		826.4
Generation		-		-		1,134.0		33.9		-		-		1,131.2		21.1
Property, Plant and Equipment, Gross		8,143.3		6,553.3		3,476.6		1,641.3		8,002.6		6,467.0		3,435.1		1,604.1
Less: Accumulated Depreciation		(1,867.9)		(1,700.6)		(1,045.3)		(283.7)		(1,804.1)		(1,631.3)		(1,021.8)		(271.5)
Property, Plant and Equipment, Net		6,275.4		4,852.7		2,431.3		1,357.6		6,198.5		4,835.7		2,413.3		1,332.6
Construction Work in Progress		317.4		294.5		88.6		61.1		252.8		208.2		54.3		48.5
Total Property, Plant and Equipment, Net	$	6,592.8	$	5,147.2	$	2,519.9	$	1,418.7	$	6,451.3	$	5,043.9	$	2,467.6	$	1,381.1

DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products for their customers, which are subject to price volatility. The costs associated with supplying energy to customers are recoverable through customer rates. The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative and nonderivative contracts.

Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the statements of income, as applicable, as electricity or natural gas is delivered.

Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets. For the Regulated companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as costs are recovered from, or refunded to, customers in their respective energy supply rates. For NU's unregulated wholesale marketing contracts that expired on December 31, 2013, changes in fair values of derivatives were included in Net Income.

The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, on the balance sheets. Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability. The following tables present the gross fair values of contracts categorized by risk type and the net amount recorded as current or long-term derivative asset or liability:


		As of June 30, 2014
		Commodity Supply and				Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		Netting ⁽¹⁾		Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
	NU⁽¹⁾	$	0.4	$	(0.1)	$	0.3
Level 3:
	NU, CL&P⁽¹⁾		16.4		(4.8)		11.6

Long-Term Derivative Assets:
Level 3:
	NU, CL&P⁽¹⁾	$	111.7	$	(17.0)	$	94.7

Current Derivative Liabilities:
Level 2:
	NU⁽¹⁾	$	(0.7)	$	0.2	$	(0.5)
Level 3:
	NU		(87.8)		-		(87.8)
	CL&P		(85.6)		-		(85.6)
	NSTAR Electric		(2.2)		-		(2.2)

Long-Term Derivative Liabilities:
Level 3:
	NU	$	(449.4)	$	-	$	(449.4)
	CL&P		(445.3)		-		(445.3)
	NSTAR Electric		(4.1)		-		(4.1)


		As of December 31, 2013
		Commodity Supply and				Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		Netting ⁽¹⁾		Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
	NU⁽¹⁾	$	1.9	$	(0.3)	$	1.6
Level 3:
	NU⁽¹⁾		18.4		(9.8)		8.6
	CL&P⁽¹⁾		17.1		(9.8)		7.3
	NSTAR Electric		1.2		-		1.2

Long-Term Derivative Assets:
Level 2:
	NU	$	0.2	$	-	$	0.2
Level 3:
	NU⁽¹⁾		116.2		(42.2)		74.0
	CL&P⁽¹⁾		113.6		(42.2)		71.4

Current Derivative Liabilities:
Level 3:
	NU	$	(93.7)	$	-	$	(93.7)
	CL&P		(92.2)		-		(92.2)
	NSTAR Electric		(1.5)		-		(1.5)

Long-Term Derivative Liabilities:
Level 3:
	NU	$	(624.1)	$	-	$	(624.1)
	CL&P		(617.1)		-		(617.1)
	NSTAR Electric		(7.0)		-		(7.0)

⁽¹⁾

Amounts represent derivative assets and liabilities that NU elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.

For further information on the fair value of derivative contracts, see Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," to the financial statements.

Derivatives Not Designated as Hedges

Commodity Supply and Price Risk Management: As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The combined capacity of these contracts is 787 MW. The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.

NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018 and a capacity-related contract to purchase up to 35 MW per year through 2019.

As of June 30, 2014 and December 31, 2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 6.6 million and 9.1 million MMBtu of natural gas, respectively.

The following table presents the current change in fair value, primarily recovered through rates from customers, associated with NU's derivative contracts not designated as hedges:


		Amounts Recognized on Derivatives
		For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Millions of Dollars)		2014		2013		2014		2013
NU
Balance Sheets:
	Regulatory Assets and Liabilities	$	111.6	$	22.2	$	166.0	$	50.1
Statements of Income:
	Purchased Power, Fuel and Transmission		-		0.5		-		0.8

Credit Risk

Certain of NU's derivative contracts contain credit risk contingent features. These features require NU to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. As of June 30, 2014, NSTAR Gas had derivative contracts in a net liability position that were subject to credit risk contingent features. If NSTAR Gas' credit rating was downgraded below investment grade, NU would have been required to post approximately $0.6 million in collateral. As of December 31, 2013, there were no derivative contracts in a net liability position that were subject to credit risk contingent features.

Valuation of Derivative Instruments

Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using NYMEX natural gas prices. Valuations of these contracts also incorporate discount rates using the yield curve approach.

The fair value of derivative contracts classified as Level 3 utilizes significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow valuations adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. 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 future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.

Valuations of derivative contracts using a discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the Company's credit rating for liabilities. Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.

The following is a summary of NU's, including CL&P's and NSTAR Electric's, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:


	As of June 30, 2014							As of December 31, 2013
		Range					Period Covered		Range					Period Covered
Energy Prices:
NU	$	63	-	66	per MWh		2018 - 2020	$	49	-	77	per MWh		2018 - 2029
CL&P	$	63	-	66	per MWh		2018 - 2020	$	56	-	58	per MWh		2018 - 2029

Capacity Prices:
NU	$	3.13	-	13.00		per kW-Month	2016 - 2026	$	5.07	-	11.82		per kW-Month	2017 - 2029
CL&P	$	7.00	-	13.00		per kW-Month	2018 - 2026	$	5.07	-	10.42		per kW-Month	2017 - 2026
NSTAR Electric	$	3.13	-	11.13		per kW-Month	2016 - 2019	$	5.07	-	7.38		per kW-Month	2017 - 2019

Forward Reserve:
NU, CL&P	$	3.30	-	9.50		per kW-Month	2014 - 2024	$	3.30	-	3.30		per kW-Month	2014 - 2024

REC Prices:
NU	$	38	-	70	per REC		2014 - 2018	$	36	-	87	per REC		2014 - 2029
NSTAR Electric	$	38	-	70	per REC		2014 - 2018	$	36	-	70	per REC		2014 - 2018

Exit price premiums of 8 percent through 25 percent are also applied on these contracts and reflect the most recent market activity available for similar type contracts.

Significant increases or decreases in future energy or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in the risk premiums would increase the fair value of the derivative liabilities. Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.

Valuations using significant unobservable inputs: The following tables present changes in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis.


		For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2014		2013		2014		2013
(Millions of Dollars)		NU		NU		NU		NU
Derivatives, Net:
Fair Value as of Beginning of Period		$	(564.3)	$	(833.1)	$	(635.2)	$	(878.6)
Net Realized/Unrealized Gains Included in:
	Net Income		-		1.3		-		7.1
	Regulatory Assets and Liabilities		111.8		22.7		161.3		48.9
Settlements			21.6		21.0		43.0		34.5
Fair Value as of End of Period		$	(430.9)	$	(788.1)	$	(430.9)	$	(788.1)


	For the Three Months Ended June 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(557.0)	$	(7.3)	$	(819.6)	$	(13.6)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		112.2		(0.4)		21.9		(0.5)
Settlements		20.2		1.4		21.9		1.0
Fair Value as of End of Period	$	(424.6)	$	(6.3)	$	(775.8)	$	(13.1)


	For the Six Months Ended June 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(630.6)	$	(7.3)	$	(866.2)	$	(14.9)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		164.5		(0.5)		46.3		0.2
Settlements		41.5		1.5		44.1		1.6
Fair Value as of End of Period	$	(424.6)	$	(6.3)	$	(775.8)	$	(13.1)

MARKETABLE SECURITIES

NU maintains trusts to fund certain non-qualified executive benefits and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability. These trusts hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. In addition, CYAPC and YAEC maintain legally restricted trusts, each of which holds marketable securities, for settling the decommissioning obligations of their nuclear power plants.

In accordance with applicable accounting guidance, the Company elected to record mutual funds designated as available-for-sale at fair value and certain other equity investments as trading securities, with the changes in fair values recorded in Other Income, Net on the statements of income. As of June 30, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $59.6 million and $24.9 million, respectively. As of December 31, 2013, the mutual funds were classified as Level 1, and totaled $57.2 million. Net gains on the mutual funds were $2.2 million and $0.1 million for the three months ended June 30, 2014 and 2013, respectively, and $2.4 million and $4.3 million for the six months ended June 30, 2014 and 2013, respectively. Net gains on the equity investments were $0.9 million and $1.4 million for the three and six months ended June 30, 2014, respectively. Dividend income is recorded in Other Income, Net on the statements of income when dividends are declared. All other marketable securities are accounted for as available-for-sale.

Available-for-Sale Securities: The following is a summary of NU's and WMECO's available-for-sale securities. These securities are recorded at fair value and included in current and long-term Marketable Securities on the balance sheets.


		As of June 30, 2014
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities⁽¹⁾	$	308.3	$	7.3	$	(0.3)	$	315.3
	Equity Securities⁽¹⁾		163.5		66.7		-		230.2

WMECO
	Debt Securities⁽²⁾		58.0		-		-		58.0


		As of December 31, 2013
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities⁽¹⁾	$	299.2	$	2.5	$	(2.1)	$	299.6
	Equity Securities⁽¹⁾		163.6		60.5		-		224.1

WMECO
	Debt Securities⁽²⁾		57.9		-		-		57.9

⁽¹⁾

NU's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $444.3 million and $424 million as of June 30, 2014 and December 31, 2013, respectively, which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the balance sheets, with no impact on the statements of income. All of the equity securities accounted for as available-for-sale securities are held in the CYAPC and YAEC trusts.

⁽²⁾

Unrealized gains and losses on debt securities held by WMECO are recorded in Other Long-Term Assets on the balance sheets.

Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for NU or WMECO. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.

Realized Gains and Losses: Realized gains and losses on available-for-sale securities are recorded in Other Income, Net for NU's benefit trust, Other Long-Term Assets for WMECO, and offset in Other Long-Term Liabilities for CYAPC and YAEC. NU utilizes the specific identification basis method for the NU benefit trust and the average cost basis method for the WMECO trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.

Contractual Maturities: As of June 30, 2014, the contractual maturities of available-for-sale debt securities are as follows:


	NU				WMECO
	Amortized				Amortized
(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value
Less than one year⁽¹⁾	$	75.9	$	75.8	$	19.2	$	19.2
One to five years		73.9		74.6		31.9		32.0
Six to ten years		56.1		57.7		2.7		2.7
Greater than ten years		102.4		107.2		4.2		4.1
Total Debt Securities	$	308.3	$	315.3	$	58.0	$	58.0

⁽¹⁾

Amounts in the Less than one year NU category include securities in the CYAPC and YAEC nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the balance sheets.

Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:


		NU				WMECO
		As of				As of
(Millions of Dollars)		June 30, 2014		December 31, 2013		June 30, 2014		December 31, 2013
Level 1:
	Mutual Funds and Equities	$	314.7	$	281.3	$	-	$	-
	Money Market Funds		42.3		32.9		2.0		10.9
Total Level 1		$	357.0	$	314.2	$	2.0	$	10.9
Level 2:
	U.S. Government Issued Debt Securities (Agency and Treasury)	$	40.6	$	61.4	$	-	$	6.8
	Corporate Debt Securities		61.8		53.6		15.8		15.1
	Asset-Backed Debt Securities		36.5		30.4		15.2		9.0
	Municipal Bonds		109.5		105.5		11.7		11.2
	Other Fixed Income Securities		24.6		15.8		13.3		4.9
Total Level 2		$	273.0	$	266.7	$	56.0	$	47.0
Total Marketable Securities		$	630.0	$	580.9	$	58.0	$	57.9

U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

SHORT-TERM AND LONG-TERM DEBT

Credit Agreements and Commercial Paper Programs: Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their joint $1.45 billion revolving credit facility to extend the expiration date an additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of June 30, 2014 and December 31, 2013, NU had $710.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $739.5 million and $435.5 million of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of June 30, 2014, there were intercompany loans from NU of $6.4 million to CL&P, $95 million to PSNH and $15.9 million to WMECO. As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.

Effective July 23, 2014, NSTAR Electric amended its $450 million revolving credit facility to extend the expiration date an additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014 and December 31, 2013, NSTAR Electric had $194.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5 million and $346.5 million of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.

Amounts outstanding under the commercial paper programs are generally included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the balance sheets as all borrowings are outstanding for no more than 364 days at one time. Intercompany loans from NU to CL&P, PSNH and WMECO are included in Notes Payable to NU Parent and classified in current liabilities on the balance sheets. See the Long-Term Debt portion of this Note immediately below for further information on the Yankee Gas $100 million bond issuance and its impact on the NU balance sheet as of December 31, 2013.

Short-Term Borrowing Limits: The amount of short-term borrowings that may be incurred by NSTAR Electric is subject to periodic approval by the FERC. On June 11, 2014, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 24, 2014 through October 23, 2016.

Long-Term Debt: On January 2, 2014, Yankee Gas issued $100 million of 4.82 percent Series L First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and to pay $25 million in short-term borrowings. In accordance with applicable accounting guidance, these amounts were classified as Long-Term Debt on NU's balance sheet as of December 31, 2013.

On March 7, 2014, NSTAR Electric issued $300 million of 4.40 percent debentures, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014.

On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in April 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings.

On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bonds using short-term debt.

Working Capital: Each of NU, CL&P, NSTAR Electric, PSNH and WMECO use its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU's transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU's Regulated companies recover their electric and natural gas distribution construction expenditures as the related project costs are depreciated over the life of the assets. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in current liabilities exceeding current assets by approximately $730 million, $220 million and $200 million at NU, CL&P and NSTAR Electric, respectively, as of June 30, 2014.

As of June 30, 2014, $366.7 million of NU's obligations classified as current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $312 million for CL&P, $4.7 million at NSTAR Electric and $50 million for PSNH. In addition, $28.9 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, determined considering capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

The components of net periodic benefit expense for the Pension, SERP and PBOP Plans are detailed below. The net periodic benefit expense less the capitalized portion of pension and PBOP amounts is included in Operations and Maintenance on the statements of income. Capitalized pension and PBOP amounts relate to employees working on capital projects and are included in Property, Plant and Equipment, Net. Intercompany allocations are not included in the CL&P, NSTAR Electric, PSNH and WMECO net periodic benefit expense amounts.


	Pension and SERP				Pension and SERP
	For the Three Months Ended				For the Six Months Ended
	June 30, 2014		June 30, 2013		June 30, 2014		June 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	19.1	$	24.6	$	41.5	$	51.1
Interest Cost		56.3		51.9		113.0		103.5
Expected Return on Plan Assets		(77.7)		(68.6)		(155.4)		(139.0)
Actuarial Loss		31.7		52.6		64.7		105.5
Prior Service Cost		1.1		1.0		2.1		2.1
Total Net Periodic Benefit Expense	$	30.5	$	61.5	$	65.9	$	123.2
Capitalized Pension Expense	$	8.7	$	19.9	$	18.4	$	36.6

	PBOP				PBOP
	For the Three Months Ended				For the Six Months Ended
	June 30, 2014		June 30, 2013		June 30, 2014		June 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	3.2	$	3.7	$	6.3	$	8.5
Interest Cost		12.1		10.9		24.7		23.6
Expected Return on Plan Assets		(15.8)		(13.9)		(31.6)		(27.7)
Actuarial Loss		3.0		4.7		6.0		13.0
Prior Service Credit		(0.7)		(0.5)		(1.4)		(1.1)
Total Net Periodic Benefit Expense	$	1.8	$	4.9	$	4.0	$	16.3
Capitalized PBOP Expense	$	0.4	$	1.5	$	0.8	$	5.0


	Pension and SERP
	For the Three Months Ended June 30, 2014								For the Three Months Ended June 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric⁽¹⁾		PSNH		WMECO
Service Cost	$	5.0	$	3.0	$	2.3	$	0.8	$	6.3	$	7.3	$	3.2	$	1.2
Interest Cost		12.4		10.3		5.8		2.5		12.1		14.7		5.9		2.5
Expected Return on Plan Assets		(18.7)		(15.7)		(9.3)		(4.4)		(18.4)		(20.2)		(9.2)		(4.4)
Actuarial Loss		8.2		5.9		2.8		1.7		13.9		14.6		5.4		2.9
Prior Service Cost/(Credit)		0.5		-		0.1		0.1		0.5		(0.1)		0.1		0.1
Total Net Periodic Benefit Expense	$	7.4	$	3.5	$	1.7	$	0.7	$	14.4	$	16.3	$	5.4	$	2.3
Intercompany Allocations	$	7.5	$	1.4	$	2.1	$	1.4	$	11.3	$	(2.2)	$	2.6	$	2.0
Capitalized Pension Expense	$	4.4	$	1.0	$	0.8	$	0.6	$	7.0	$	6.5	$	1.7	$	1.3

	Pension and SERP
	For the Six Months Ended June 30, 2014								For the Six Months Ended June 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric⁽¹⁾		PSNH		WMECO
Service Cost	$	10.2	$	7.6	$	5.1	$	1.9	$	12.4	$	16.5	$	6.5	$	2.4
Interest Cost		25.7		20.6		12.3		5.2		24.2		29.0		11.9		5.0
Expected Return on Plan Assets		(38.0)		(31.5)		(19.5)		(9.0)		(36.9)		(42.2)		(16.8)		(8.7)
Actuarial Loss		17.3		11.7		6.0		3.5		28.0		29.1		10.8		5.9
Prior Service Cost/(Credit)		0.9		-		0.3		0.2		0.9		(0.1)		0.3		0.2
Total Net Periodic Benefit Expense	$	16.1	$	8.4	$	4.2	$	1.8	$	28.6	$	32.3	$	12.7	$	4.8
Intercompany Allocations	$	14.3	$	3.8	$	4.2	$	2.7	$	22.1	$	(4.1)	$	5.2	$	4.0
Capitalized Pension Expense	$	9.3	$	2.9	$	1.7	$	1.4	$	14.0	$	11.8	$	3.9	$	2.6


	PBOP
	For the Three Months Ended June 30, 2014								For the Three Months Ended June 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	0.5	$	0.8	$	0.3	$	0.1	$	0.9	$	0.6	$	0.2
Interest Cost		1.9		4.8		1.0		0.4		2.0		1.0		0.4
Expected Return on Plan Assets		(2.5)		(6.5)		(1.3)		(0.6)		(2.5)		(1.3)		(0.6)
Actuarial Loss/(Gain)		1.0		(0.2)		0.6		0.1		1.9		0.9		0.3
Prior Service Credit		-		(0.5)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	0.9	$	(1.6)	$	0.6	$	0.0	$	2.3	$	1.2	$	0.3
Intercompany Allocations	$	1.1	$	-	$	0.3	$	0.2	$	1.9	$	0.4	$	0.3
Capitalized PBOP Expense/(Income)	$	0.5	$	(0.5)	$	0.2	$	-	$	1.2	$	0.4	$	0.2

	PBOP
	For the Six Months Ended June 30, 2014								For the Six Months Ended June 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	1.1	$	1.6	$	0.7	$	0.2	$	1.7	$	1.1	$	0.4
Interest Cost		4.0		9.7		2.1		0.8		3.9		2.0		0.8
Expected Return on Plan Assets		(5.2)		(13.0)		(2.7)		(1.1)		(5.0)		(2.6)		(1.2)
Actuarial Loss/(Gain)		2.1		(0.3)		1.1		0.2		3.7		1.8		0.6
Prior Service Credit		-		(0.9)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	2.0	$	(2.9)	$	1.2	$	0.1	$	4.3	$	2.3	$	0.6
Intercompany Allocations	$	2.2	$	0.1	$	0.6	$	0.4	$	3.6	$	0.8	$	0.6
Capitalized PBOP Expense/(Income)	$	1.0	$	(1.0)	$	0.4	$	0.1	$	2.4	$	0.7	$	0.4

⁽¹⁾

NSTAR Electric's pension amounts for the three and six months ended June 30, 2013 do not include SERP expense.

For the three and six months ended June 30, 2013, the net periodic PBOP expense allocated to NSTAR Electric was a benefit of $2 million and an expense of $2.3 million, respectively.

As of December 31, 2013, the funded status of the NSTAR Pension Plan was recorded on NSTAR Electric's balance sheet while the total SERP obligation and PBOP Plan funded status were recorded on NSTAR Electric & Gas' balance sheet. As of December 31, 2013, all NSTAR employees were employed by NSTAR Electric & Gas. On January 1, 2014, NSTAR Electric & Gas was merged into NUSCO and, concurrently, all employees were transferred to the company they predominately provide services for: NUSCO, NSTAR Electric or NSTAR Gas. As a result of the employee transfers, the pension and PBOP assets and liabilities were attributed by participant and transferred to the respective company's balance sheets.

As of June 30, 2014, the liabilities associated with the Pension, SERP and PBOP plans for NSTAR Electric were $85.8 million for the Pension Plan, $3.6 million for the SERP Plans ($0.4 million of which is included in other current liabilities) and $61.2 million for the PBOP Plan. As of December 31, 2013, the liability associated with the NSTAR Pension Plan for NSTAR Electric was $118 million. This change had no impact on the income statement or net assets of NSTAR Electric or NU.

COMMITMENTS AND CONTINGENCIES

Environmental Matters

General: NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.

The number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed are as follows:


	As of June 30, 2014				As of December 31, 2013
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		66	$	34.5		68	$	35.4
CL&P		17		4.2		18		3.4
NSTAR Electric		14		1.2		12		1.2
PSNH		13		5.3		15		5.4
WMECO		5		0.6		5		0.4

Included in the NU number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was $29.8 million and $31.4 million as of June 30, 2014 and December 31, 2013, respectively, and relates primarily to the natural gas business segment.

Long-Term Contractual Arrangements

The following is an update to the current status of long-term contractual arrangements set forth in Note 12B of the NU 2013 Form 10-K.

Renewable Energy: Renewable energy contracts include non-cancelable commitments under contracts of NSTAR Electric and WMECO for the purchase of energy and capacity from renewable energy facilities.


	July - December
(Millions of Dollars)	2014		2015		2016		2017		2018		Thereafter		Total
Renewable Energy
NSTAR Electric	$	43.6	$	86.3	$	93.7	$	89.8	$	53.3	$	302.8	$	669.5
WMECO		-		-		2.4		2.4		2.4		28.9		36.1

Contractual Obligations – Yankee Companies

Spent Nuclear Fuel Litigation - DOE Phase II Damages - On November 15, 2013, the Court of Federal Claims issued an award to CYAPC for $126.3 million, YAEC for $73.3 million and MYAPC for $35.8 million for lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 (DOE Phase II Damages). On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment.

On March 28, 2014, CYAPC, YAEC and MYAPC received payment of $90 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds. On April 24, 2014, CYAPC received payment of the remaining $36.3 million proceeds. On April 28, 2014, the Yankee Companies made the required informational filing with FERC in accordance with the process and methodology outlined in the 2013 FERC order. The Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, on June 1, 2014.

As of June 30, 2014, CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each company's respective regulatory tracker mechanisms. For further information, see Note 2, "Regulatory Accounting," to the financial statements.

DOE Phase III Damages - On August 15, 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012. Responsive pleading from the U.S. Department of Justice was filed on November 18, 2013, and discovery has begun.

Guarantees and Indemnifications

NU parent provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, in the form of guarantees in the normal course of business.

NU provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises and the termination of an unregulated business, with maximum exposures either not specified or not material.

NU also issued a guaranty under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NU will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $25 million. NU's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.

Management does not anticipate a material impact to Net Income as a result of these various guarantees and indemnifications.

The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of June 30, 2014:


		Maximum Exposure
Subsidiary	Description	(in millions)		Expiration Dates

Various	Surety Bonds	$	67.0	2014 - 2016⁽¹⁾

Various	New England Hydro Companies' Long-Term Debt	$	2.5	Unspecified

NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	16.0	2019 and 2024

⁽¹⁾

Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended.

Certain surety bonds contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU are downgraded.

FERC Base ROE Complaints

On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants"). The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets. Complainants sought an order to reduce the base ROE, effective October 1, 2011, and to require refunds. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.

On August 6, 2013, the FERC ALJ issued an initial decision finding that the base ROE in effect from October 1, 2011 through December 31, 2012 (refund period) was not reasonable, and recommended separate base ROEs for the refund period of 10.6 percent and for the period beginning when FERC issues its final decision (prospective period) of 9.7 percent, leaving policy considerations and additional adjustments to the FERC. In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. The aggregate after-tax charge to third quarter 2013 earnings totaled $14.3 million at NU, which represented reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

On June 19, 2014, FERC issued an order partially affirming and partially reversing the ALJ's initial decision. FERC set a single tentative base ROE of 10.57 percent for the refund period and prospective period. FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects. Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE at the 75^th percentile of this new zone. FERC also stated that a utility's total ROE inclusive of transmission incentive ROE adders, should not exceed the top of the new zone of reasonableness produced by this methodology. FERC instituted a paper hearing on the long-term growth rate portion of the methodology, before it issues a final determination on the base ROE. On July 21, 2014, the NETOs and Complainants filed rehearing requests in this proceeding.

On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties, which challenged the NETOs' base ROE and sought refunds for the 15-month period beginning January 1, 2013. On June 19, 2014, the FERC issued a second order finding that the complaint raised issues of material fact, and set this complaint for trial, should settlement negotiations be unsuccessful. FERC stated that it could issue an order in this case by mid-2016. On July 21, 2014, the NETOs filed a rehearing request in this proceeding.

Though NU cannot predict the ultimate outcome of this proceeding, in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s two orders issued on June 19, 2014 for the two refund periods. The aggregate after-tax charge to second quarter 2014 earnings totaled $32.1 million at NU, which represented reserves of $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO.

As of June 30, 2014, the cumulative pre-tax reserves totaled $79.3 million at NU, $44.7 million at CL&P, $16.2 million at NSTAR Electric, $6.2 million at PSNH and $12.2 million at WMECO. As of December 31, 2013, the pre-tax reserves totaled $24.6 million at NU, $13.3 million at CL&P, $5.9 million at NSTAR Electric, $2.4 million at PSNH and $3 million at WMECO. The reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of operating revenues. See Note 2, “Regulatory Accounting,” for further information.

On July 31, 2014, the Complainants filed an additional complaint with FERC. At this time, the Company cannot determine the outcome of this complaint.

CPSL

Since 2006, NSTAR Electric has been recovering incremental costs related to the DPU-approved Safety and Reliability Programs. From 2006 through 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.

On May 28, 2010, the DPU issued an order on NSTAR Electric's 2006 CPSL cost recovery filing (the May 2010 Order). In October 2010, NSTAR Electric filed a reconciliation of the cumulative CPSL program activity for the periods 2006 through 2009 with the DPU in order to determine a proposed rate adjustment. The DPU allowed the proposed rates to go into effect January 1, 2011, subject to final reconciliation of CPSL program costs through a future DPU proceeding. In February 2013, NSTAR Electric updated the October 2010 filing with final activity through 2011. NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.

NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011. While management does not believe that any subsequent DPU order would result in revenues that are materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric's results of operations, financial position and cash flows.

Basic Service Bad Debt Adder

In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. The DPU issued an order approving the implementation of a revised Basic Service rate but instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs. This adjustment to NSTAR Electric's distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.

In 2010, NSTAR Electric filed an appeal of the DPU's order with the SJC. In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review. The DPU has not taken any action on the remand.

NSTAR Electric deferred approximately $34 million of costs associated with energy-related bad debt as a regulatory asset through 2011 as NSTAR Electric had concluded that it was probable that these costs would ultimately be recovered from customers. Due to the delays and the duration of the proceedings, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not," it could no longer be deemed "probable." As a result, NSTAR Electric recognized a reserve related to the regulatory asset in 2012. NSTAR Electric will continue to maintain the reserve until the proceeding has been concluded with the DPU.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Preferred Stock and Long-Term Debt: The fair value of CL&P's and NSTAR Electric's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate long-term debt securities are assumed to have a fair value equal to their carrying value. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:


	As of June 30, 2014				As of December 31, 2013
	NU				NU
	Carrying		Fair		Carrying		Fair
(Millions of Dollars)	Amount		Value		Amount		Value
Preferred Stock Not Subject to Mandatory Redemption	$	155.6	$	150.1	$	155.6	$	152.7
Long-Term Debt		8,542.7		9,008.4		8,310.2		8,443.1


	As of June 30, 2014
	CL&P				NSTAR Electric				PSNH				WMECO
	Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)	Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not Subject to Mandatory Redemption	$	116.2	$	110.3	$	43.0	$	39.8	$	-	$	-	$	-	$	-
Long-Term Debt		2,991.6		3,344.5		1,797.4		1,949.8		1,049.2		1,105.8		628.9		665.3

	As of December 31, 2013
	CL&P				NSTAR Electric				PSNH				WMECO
	Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)	Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not Subject to Mandatory Redemption	$	116.2	$	110.5	$	43.0	$	42.2	$	-	$	-	$	-	$	-
Long-Term Debt		2,741.2		2,952.8		1,801.1		1,888.0		1,049.0		1,073.9		629.4		640.1

Derivative Instruments: Derivative instruments are carried at fair value. For further information, see Note 4, "Derivative Instruments," to the financial statements.

Other Financial Instruments: Investments in marketable securities are carried at fair value. For further information, see Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 5, "Marketable Securities," to the financial statements. The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.

10.

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

The changes in accumulated other comprehensive income/(loss) by component, net of tax, is as follows:


	For the Six Months Ended June 30, 2014								For the Six Months Ended June 30, 2013
			Unrealized		Pension,						Unrealized		Pension,
	Qualified		Gains/(Losses)		SERP and				Qualified		Gains/(Losses)		SERP and
	Cash Flow		on Available-		PBOP				Cash Flow		on Available-		PBOP
	Hedging		for-Sale		Benefit				Hedging		for-Sale		Benefit
(Millions of Dollars)	Instruments		Securities		Plans		Total		Instruments		Securities		Plans		Total
AOCI as of Beginning of Period	$	(14.4)	$	0.4	$	(32.0)	$	(46.0)	$	(16.4)	$	1.3	$	(57.8)	$	(72.9)

OCI Before Reclassifications		-		0.5		1.2		1.7		-		(0.7)		-		(0.7)
Amounts Reclassified from AOCI		1.0		-		1.8		2.8		1.0		-		3.1		4.1
Net OCI		1.0		0.5		3.0		4.5		1.0		(0.7)		3.1		3.4
AOCI as of End of Period	$	(13.4)	$	0.9	$	(29.0)	$	(41.5)	$	(15.4)	$	0.6	$	(54.7)	$	(69.5)

NU's qualified cash flow hedging instruments represent interest rate swap agreements on debt issuances that were settled in prior years. The settlement amount was recorded in AOCI and is being amortized into Net Income over the term of the underlying debt instrument. CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt, which are not material to their respective financial statements.

The following table sets forth the amounts reclassified from AOCI by component and the impacted line item on the statements of income:


	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	Amounts Reclassified				Amounts Reclassified				Statements of Income
	from AOCI				from AOCI				Line Item Impacted
(Millions of Dollars)	2014		2013		2014		2013
Qualified Cash Flow Hedging Instruments	$	(0.8)	$	(0.8)	$	(1.7)	$	(1.7)	Interest Expense
Tax Benefit		0.3		0.3		0.7		0.7	Income Tax Expense
Qualified Cash Flow Hedging Instruments, Net of Tax	$	(0.5)	$	(0.5)	$	(1.0)	$	(1.0)

Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses	$	(1.2)	$	(2.2)	$	(2.9)	$	(4.7)	Operations and Maintenance⁽¹⁾
Amortization of Prior Service Cost		-		-		(0.1)		(0.1)	Operations and Maintenance⁽¹⁾
Total Pension, SERP and PBOP Benefit Plan Costs		(1.2)		(2.2)		(3.0)		(4.8)
Tax Benefit		0.5		0.7		1.2		1.7	Income Tax Expense
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax	$	(0.7)	$	(1.5)	$	(1.8)	$	(3.1)

Total Amounts Reclassified from AOCI, Net of Tax	$	(1.2)	$	(2.0)	$	(2.8)	$	(4.1)

⁽¹⁾

These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions," for further information.

11.

COMMON SHARES

The following table sets forth the NU common shares and the shares of common stock of CL&P, NSTAR Electric, PSNH and WMECO that were authorized and issued and the respective per share par values:


	Shares
			Authorized as of
	Per Share		June 30, 2014 and	Issued as of
	Par Value		December 31, 2013	June 30, 2014	December 31, 2013
NU	$	5	380,000,000	333,327,485	333,113,492
CL&P	$	10	24,500,000	6,035,205	6,035,205
NSTAR Electric	$	1	100,000,000	100	100
PSNH	$	1	100,000,000	301	301
WMECO	$	25	1,072,471	434,653	434,653

As of June 30, 2014 and December 31, 2013, there were 17,108,131 and 17,796,672 NU common shares held as treasury shares, respectively. As of June 30, 2014 and December 31, 2013, NU common shares outstanding were 316,219,354 and 315,273,559, respectively.


12. COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:

	For the Three Months Ended
	June 30, 2014				June 30, 2013
			Noncontrolling				Noncontrolling
			Interest -				Interest -
	Common		Preferred		Common		Preferred
	Shareholders'		Stock of		Shareholders'		Stock of
(Millions of Dollars)	Equity		Subsidiaries		Equity		Subsidiaries
Balance as of Beginning of Period	$	9,723.9	$	155.6	$	9,345.2	$	155.6
Net Income		129.2		-		173.1		-
Dividends on Common Shares		(124.1)		-		(115.6)		-
Dividends on Preferred Stock		(1.9)		(1.9)		(2.0)		(2.0)
Issuance of Common Shares		0.2		-		0.3		-
Other Transactions, Net		23.7		-		4.2		-
Net Income Attributable to Noncontrolling Interests		-		1.9		-		2.0
Other Comprehensive Income		2.8		-		1.4		-
Balance as of End of Period	$	9,753.8	$	155.6	$	9,406.6	$	155.6


	For the Six Months Ended
	June 30, 2014				June 30, 2013
			Noncontrolling				Noncontrolling
			Interest -				Interest -
	Common		Preferred		Common		Preferred
	Shareholders'		Stock of		Shareholders'		Stock of
(Millions of Dollars)	Equity		Subsidiaries		Equity		Subsidiaries
Balance as of Beginning of Period	$	9,611.5	$	155.6	$	9,237.1	$	155.6
Net Income		367.1		-		403.0		-
Dividends on Common Shares		(247.9)		-		(232.1)		-
Dividends on Preferred Stock		(3.8)		(3.8)		(3.9)		(3.9)
Issuance of Common Shares		5.4		-		8.8		-
Other Transactions, Net		17.0		-		(9.7)		-
Net Income Attributable to Noncontrolling Interests		-		3.8		-		3.9
Other Comprehensive Income		4.5		-		3.4		-
Balance as of End of Period	$	9,753.8	$	155.6	$	9,406.6	$	155.6

13.

EARNINGS PER SHARE

Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards as if they were converted into common shares. There were no antidilutive share awards outstanding for the three and six months ended June 30, 2014 or for the three months ended June 30, 2013. For the six months ended June 30, 2013, there were 3,150 antidilutive share awards excluded from the computation.

The following table sets forth the components of basic and diluted EPS:


		For the Three Months Ended				For the Six Months Ended
(Millions of Dollars, except share information)		June 30, 2014		June 30, 2013		June 30, 2014		June 30, 2013
Net Income Attributable to Controlling Interest		$	127.4	$	171.0	$	363.3	$	399.1

Weighted Average Common Shares Outstanding:
	Basic		315,950,510		315,154,130		315,742,511		315,141,956
	Dilutive Effect		1,162,291		808,489		1,259,950		840,622
	Diluted		317,112,801		315,962,619		317,002,461		315,982,578
Basic EPS		$	0.40	$	0.54	$	1.15	$	1.27
Diluted EPS		$	0.40	$	0.54	$	1.15	$	1.26

RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).

The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).

14.

SEGMENT INFORMATION

Presentation: NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution reportable segments and Other based on a combination of factors, including the characteristics of each segments' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. These reportable segments represented substantially all of NU's total consolidated revenues for the three and six months ended June 30, 2014 and 2013. Revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The Electric Distribution reportable segment includes the generation activities of PSNH and WMECO.

The remainder of NU's operations is presented as Other in the tables below and primarily consists of 1) the equity in earnings of NU parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest expense related to the debt of NU parent, 2) the revenues and expenses of NU's service company, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other non-regulated subsidiaries, which are not part of its core business.

Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense.

NU's reportable segments are determined based upon the level at which NU's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of NU's subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. NU's operating segments and reporting units are consistent with its reportable business segments.

NU's segment information is as follows:


	For the Three Months Ended June 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,261.8	$	195.5	$	206.9	$	184.7	$	(171.3)	$	1,677.6
Depreciation and Amortization		(89.3)		(16.9)		(37.0)		(7.7)		2.3		(148.6)
Other Operating Expenses		(991.5)		(166.5)		(71.0)		(174.9)		168.9		(1,235.0)
Operating Income		181.0		12.1		98.9		2.1		(0.1)		294.0
Interest Expense		(47.2)		(8.7)		(28.8)		(9.1)		1.3		(92.5)
Other Income, Net		2.9		-		2.7		137.7		(137.8)		5.5
Net Income Attributable to Controlling Interest	$	83.4	$	2.0	$	43.9	$	133.3	$	(135.2)	$	127.4

	For the Six Months Ended June 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	2,847.8	$	628.3	$	458.9	$	356.9	$	(323.7)	$	3,968.2
Depreciation and Amortization		(238.2)		(34.6)		(74.0)		(14.7)		4.1		(357.4)
Other Operating Expenses		(2,202.4)		(487.9)		(137.3)		(340.3)		318.8		(2,849.1)
Operating Income		407.2		105.8		247.6		1.9		(0.8)		761.7
Interest Expense		(94.6)		(17.1)		(54.3)		(18.7)		2.2		(182.5)
Other Income, Net		4.3		0.1		4.2		432.4		(433.8)		7.2
Net Income Attributable to Controlling Interest	$	195.6	$	54.1	$	118.8	$	424.9	$	(430.1)	$	363.3
Cash Flows Used for Investments in Plant	$	335.6	$	68.6	$	289.3	$	30.5	$	-	$	724.0


	For the Three Months Ended June 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,221.6	$	154.1	$	247.9	$	220.7	$	(208.4)	$	1,635.9
Depreciation and Amortization		(152.2)		(16.7)		(34.5)		(21.7)		2.9		(222.2)
Other Operating Expenses		(883.3)		(127.0)		(63.6)		(194.9)		205.7		(1,063.1)
Operating Income		186.1		10.4		149.8		4.1		0.2		350.6
Interest Expense		(43.4)		(8.9)		(25.2)		(10.7)		1.3		(86.9)
Other Income, Net		2.2		0.1		2.8		232.2		(232.3)		5.0
Net Income Attributable to Controlling Interest	$	91.2	$	1.2	$	76.8	$	232.8	$	(231.0)	$	171.0


	For the Six Months Ended June 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	2,595.8	$	515.9	$	487.4	$	437.8	$	(406.0)	$	3,630.9
Depreciation and Amortization		(329.1)		(34.1)		(66.3)		(40.8)		4.6		(465.7)
Other Operating Expenses		(1,888.3)		(394.3)		(125.8)		(392.2)		404.9		(2,395.7)
Operating Income		378.4		87.5		295.3		4.8		3.5		769.5
Interest Expense		(85.6)		(16.2)		(47.1)		(17.1)		2.9		(163.1)
Other Income, Net		7.1		0.3		5.5		554.0		(554.2)		12.7
Net Income Attributable to Controlling Interest	$	190.6	$	44.5	$	156.7	$	555.5	$	(548.2)	$	399.1
Cash Flows Used for Investments in Plant	$	315.3	$	70.9	$	297.4	$	16.7	$	-	$	700.3


The following table summarizes NU's segmented total assets:

	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
As of June 30, 2014	$	16,942.5	$	2,753.8	$	6,934.1	$	11,566.6	$	(10,406.6)	$	27,790.4
As of December 31, 2013		17,260.0		2,759.7		6,745.8		11,842.4		(10,812.4)		27,795.5

NORTHEAST UTILITIES AND SUBSIDIARIES

Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this combined Quarterly Report on Form 10-Q, the First Quarter 2014 Form 10-Q, and the 2013 Annual Report on Form 10-K. References in this Form 10-Q to "NU," the "Company," "we," "us," and "our" refer to Northeast Utilities and its consolidated subsidiaries. All per share amounts are reported on a diluted basis. The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."

Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the year. The discussion below also includes non-GAAP financial measures referencing our second quarter and first half of 2014 and 2013 earnings and EPS excluding certain integration costs related to NU's merger with NSTAR. We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our second quarter and first half of 2014 and 2013 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.

Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interest are included under "Financial Condition and Business Analysis – Overview – Consolidated" in Management's Discussion and Analysis, herein.

Forward-Looking Statements: From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:

^·

cyber breaches, acts of war or terrorism, or grid disturbances,

^·

actions or inaction of local, state and federal regulatory and taxing bodies,

^·

changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services,

^·

fluctuations in weather patterns,

^·

changes in laws, regulations or regulatory policy,

^·

changes in levels or timing of capital expenditures,

^·

disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,

^·

developments in legal or public policy doctrines,

^·

technological developments,

^·

changes in accounting standards and financial reporting regulations,

^·

actions of rating agencies, and

^·

other presently unknown or unforeseen factors.

Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.

All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this Quarterly Report on Form 10-Q and in NU's 2013 Annual Report on Form 10-K. This Quarterly Report on Form 10-Q and NU's 2013 Annual Report on Form 10-K also describe material contingencies and critical accounting policies in the accompanying Management's Discussion and Analysis of Financial Condition and Results of Operations and Combined Notes to Condensed Consolidated Financial Statements (Unaudited). We encourage you to review these items.

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this combined Quarterly Report on Form 10-Q:

Results:

We earned $127.4 million, or $0.40 per share, in the second quarter of 2014, and $363.3 million, or $1.15 per share, in the first half of 2014, compared with $171 million, or $0.54 per share, in the second quarter of 2013 and $399.1 million, or $1.26 per share, in the first half of 2013. Excluding integration costs, we earned $131.9 million, or $0.42 per share, in the second quarter of 2014, and $373.7 million, or $1.18 per share, in the first half of 2014, compared with $172.8 million, or $0.55 per share, in the second quarter of 2013, and $402.6 million, or $1.27 per share, in the first half of 2013.

Our electric distribution segment, which includes generation, earned $83.4 million, or $0.26 per share, in the second quarter of 2014 and $195.6 million, or $0.62 per share, in the first half of 2014, compared with earnings of $91.2 million, or $0.29 per share, in the second quarter of 2013 and $190.6 million, or $0.60 per share, in the first half of 2013.

Our transmission segment earned $43.9 million, or $0.14 per share, in the second quarter of 2014 and $118.8 million, or $0.37 per share, in the first half of 2014, compared with $76.8 million, or $0.25 per share, in the second quarter of 2013 and $156.7 million, or $0.50 per share, in the first half of 2013. The decrease in the second quarter and first half of 2014 earnings, as compared to the same periods in 2013, was due primarily to the establishment of a $32.1 million after-tax reserve related to FERC ROE orders issued on June 19, 2014.

Our natural gas distribution segment earned $2 million, or $0.01 per share, in the second quarter of 2014 and $54.1 million, or $0.17 per share, in the first half of 2014, compared with $1.2 million in the second quarter of 2013 and $44.5 million, or $0.14 per share, in the first half of 2013.

NU parent and other companies had net losses of $1.9 million, or $0.01 per share, in the second quarter of 2014 and $5.2 million, or $0.01 per share, in the first half of 2014, compared with earnings of $1.8 million in the second quarter of 2013 and $7.3 million, or $0.02 per share, in the first half of 2013. Second quarter and first half 2014 results reflect $4.5 million and $10.4 million, respectively, of after-tax integration costs. Second quarter and first half 2013 results reflect $1.8 million and $3.5 million, respectively, of after-tax integration costs.

Legislative and Regulatory Items:

On June 9, 2014, CL&P filed an application with the PURA to amend customer rates, effective December 1, 2014. CL&P requested an increase in base distribution rates of $116.7 million. Based on the current schedule, we expect a final decision in December 2014.

On June 19, 2014, the FERC issued two orders in the pending base ROE complaint proceedings. The first order addressed the joint complaint filed at FERC in September 2011 by several New England parties alleging that the base ROE of 11.14 percent was unjust and unreasonable. The FERC set a single tentative base ROE of 10.57 percent for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC finalizes the base ROE). The second order addressed a second joint complaint filed at FERC in December 2012 by additional New England parties alleging that the base ROE was unjust and unreasonable. The complaint sought refunds for the 15-month period beginning January 1, 2013. The FERC found that the second complaint raised issues of material fact and set this complaint for settlement or trial if settlement negotiations should be unsuccessful. We recorded a series of reserves totaling $32.1 million after-tax at our electric subsidiaries to recognize the potential financial impact from the FERC's two orders for the two refund periods.

On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure. The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.

Liquidity:

Cash and cash equivalents totaled $34.1 million as of June 30, 2014, compared with $43.4 million as of December 31, 2013, while investments in property, plant and equipment totaled $724 million in the first half of 2014, compared with $700.3 million in the first half of 2013.

Cash flows provided by operating activities totaled $896.7 million in the first half of 2014, compared with $769 million in the first half of 2013. The improved operating cash flows were due primarily to approximately $126 million in DOE Phase II proceeds received by CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and the decrease of $82.2 million in Pension and PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first half of 2014 ($158 million), as compared to the first half of 2013 ($16 million).

In the first half of 2014, we issued $650 million of new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014, $300 million by NSTAR Electric on March 7, 2014, and $250 million by CL&P on April 24, 2014. These new issuances were used to repay approximately $375 million of existing long-term debt with the remainder used to pay short-term borrowings.

In the first half of 2014, we had cash dividends on common shares of $237.2 million, compared with $232 million in the first half of 2013. On May 1, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, which was paid on June 30, 2014 to shareholders of record as of May 30, 2014.

Overview

Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for the second quarter and first half of 2014 and 2013 is as follows:


	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars, Except	2014				2013				2014				2013
Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to Controlling Interest (GAAP)	$	127.4	$	0.40	$	171.0	$	0.54	$	363.3	$	1.15	$	399.1	$	1.26
Regulated Companies	$	129.3	$	0.41	$	169.2	$	0.54	$	368.5	$	1.16	$	391.8	$	1.24
NU Parent and Other Companies		2.6		0.01		3.6		0.01		5.2		0.02		10.8		0.03
Non-GAAP Earnings		131.9		0.42		172.8		0.55		373.7		1.18		402.6		1.27
Integration Costs (after-tax)		(4.5)		(0.02)		(1.8)		(0.01)		(10.4)		(0.03)		(3.5)		(0.01)
Net Income Attributable to Controlling Interest (GAAP)	$	127.4	$	0.40	$	171.0	$	0.54	$	363.3	$	1.15	$	399.1	$	1.26

Excluding the impact of integration costs, our second quarter 2014 earnings decreased by $40.9 million, as compared to the second quarter of 2013. The decrease was due primarily to the establishment of an after-tax reserve of $32.1 million related to the June 2014 FERC ROE orders. For further information, see "FERC Regulatory Issues – FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations. In addition, earnings decreased as a result of higher depreciation expense and property taxes and lower retail electric sales, partially offset by lower general and administrative costs.

Excluding the impact of integration costs, our first half 2014 earnings decreased by $28.9 million, as compared to the first half of 2013, due primarily to the establishment of the $32.1 million after-tax reserve related to June 2014 FERC base ROE orders, the absence of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013, and higher depreciation expense and property taxes. Earnings were favorably impacted by higher retail electric and firm natural gas sales as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013, and lower general and administrative costs.

Regulated Companies: Our Regulated companies consist of the electric distribution, transmission, and natural gas distribution segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings for the second quarter and first half of 2014 and 2013 is as follows:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		2014		2013
Electric Distribution	$	83.4	$	91.2	$	195.6	$	190.6
Transmission		43.9		76.8		118.8		156.7
Natural Gas Distribution		2.0		1.2		54.1		44.5
Net Income - Regulated Companies	$	129.3	$	169.2	$	368.5	$	391.8

Our electric distribution segment earnings decreased $7.8 million in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to a decrease of 2.9 percent in retail electric sales as a result of milder temperatures in late May and June, as compared to the same periods in 2013, the absence of regulatory interest income from stranded cost recoveries recognized in the second quarter of 2013, and higher depreciation and property tax expense, partially offset by lower general and administrative costs.

Our electric distribution segment earnings increased $5 million in the first half of 2014, as compared to the first half of 2013, due primarily to higher retail electric sales as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013, and a decrease in operations and maintenance costs that impact earnings. Partially offsetting these favorable impacts were the absence of regulatory interest income from stranded cost recoveries in 2013, and higher depreciation and property tax expense.

Our transmission segment earnings decreased $32.9 million in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to the establishment of the $32.1 million after-tax reserve related to the June 2014 FERC ROE orders, the net unfavorable impact on transmission revenues as a result of a refund to our customers in June 2014, partially offset by a higher transmission rate base as a result of an increased investment in our transmission infrastructure.

Our transmission segment earnings decreased $37.9 million in the first half of 2014, as compared to the first half of 2013, due primarily to the $32.1 million after-tax reserve related to the June 2014 FERC ROE orders, the absence of the favorable impact from the resolution of the state income tax audit in the first quarter of 2013, the net unfavorable impact on transmission revenues as a result of a refund to our customers in June 2014, partially offset by a higher transmission rate base as a result of an increased investment in our transmission infrastructure.

Our natural gas distribution segment earnings increased $0.8 million in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to higher firm natural gas sales and peak demand revenues as a result of the addition of new natural gas heating customers.

Our natural gas distribution segment earnings increased $9.6 million in the first half of 2014, as compared to the first half of 2013, due primarily to higher firm natural gas sales and peak demand revenues as a result of colder weather in the first quarter of 2014, as well as the addition of new natural gas heating customers.

A summary of our retail electric GWh sales and percentage changes, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, is as follows:


	For the Three Months Ended June 30, 2014 Compared to 2013			For the Six Months Ended June 30, 2014 Compared to 2013
	Sales (GWh)		Percentage	Sales (GWh)		Percentage
NU – Electric	2014	2013	Decrease	2014	2013	Increase
Residential	4,510	4,720	(4.4)%	10,650	10,523	1.2%
Commercial ⁽¹⁾	6,591	6,754	(2.4)%	13,456	13,448	0.1%
Industrial	1,435	1,437	(0.1)%	2,778	2,736	1.5%
Total	12,536	12,911	(2.9)%	26,884	26,707	0.7%


	For the Three Months Ended June 30, 2014 Compared to 2013				For the Six Months Ended June 30, 2014 Compared to 2013
	CL&P	NSTAR Electric	PSNH	WMECO	CL&P	NSTAR Electric	PSNH	WMECO
Electric	Percentage Increase/ (Decrease)	Percentage Decrease	Percentage Increase/ (Decrease)	Percentage Decrease	Percentage Increase	Percentage Increase/ (Decrease)	Percentage Increase	Percentage Increase/ (Decrease)
Residential	(5.3)%	(4.2)%	(1.8)%	(5.4)%	1.5%	0.2 %	2.4%	0.9 %
Commercial ⁽¹⁾	(2.0)%	(3.0)%	(0.6)%	(4.5)%	0.1%	(0.2)%	0.8%	(0.3)%
Industrial	3.4 %	(6.9)%	1.7 %	(3.2)%	3.8%	(1.9)%	3.2%	(2.8)%
Total	(2.8)%	(3.6)%	(0.6)%	(4.6)%	1.1%	(0.1)%	1.9%	(0.2)%

⁽¹⁾

Commercial retail electric GWh sales include streetlighting and railroad retail sales.

A summary of our firm natural gas sales in million cubic feet and percentage changes, as well as percentage changes in Yankee Gas and NSTAR Gas, is as follows:


	For the Three Months Ended June 30, 2014 Compared to 2013			For the Six Months Ended June 30, 2014 Compared to 2013
	Sales (million cubic feet)		Percentage	Sales (million cubic feet)		Percentage
NU – Firm Natural Gas	2014	2013	Increase	2014	2013	Increase
Residential	5,169	4,970	4.0%	24,981	21,985	13.6%
Commercial	6,839	6,622	3.3%	26,467	23,393	13.1%
Industrial	4,916	4,665	5.4%	12,393	11,494	7.8%
Total	16,924	16,257	4.1%	63,841	56,872	12.3%
Total, Net of Special Contracts ⁽¹⁾	15,895	15,238	4.3%	61,445	54,660	12.4%


	For the Three Months Ended June 30, 2014 Compared to 2013		For the Six Months Ended June 30, 2014 Compared to 2013
	Sales (million cubic feet)		Sales (million cubic feet)
	Yankee Gas	NSTAR Gas	Yankee Gas	NSTAR Gas
	Percentage	Percentage	Percentage	Percentage
Firm Natural Gas	Increase/(Decrease)	Increase	Increase/(Decrease)	Increase
Residential	(3.4)%	9.6 %	15.8%	12.2%
Commercial	5.4 %	1.4 %	16.6%	10.2%
Industrial	5.7 %	4.5%	8.4%	6.4%
Total	3.3 %	5.0%	13.9%	10.6%
Total, Net of Special Contracts ⁽¹⁾	3.7 %		14.4%

⁽¹⁾

Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.

Weather, fluctuations in energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. In our service territories, weather impacts electric sales during the summer and electric and natural gas sales during the winter (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur. In addition, our electric and natural gas businesses are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.

For the second quarter of 2014, our consolidated retail electric sales, consisting of the retail electric sales of CL&P, NSTAR Electric, PSNH, and WMECO, were lower, as compared to the same period in 2013, due primarily to milder temperatures in late May and June, compared with the same periods in 2013. The second quarter of 2014 cooling degree days were 19 percent lower in Connecticut and western Massachusetts, 22 percent lower in the Boston metropolitan area, and 24 percent lower in New Hampshire, as compared to the second quarter of 2013. Weather-normalized retail

electric sales (based on 30-year average temperatures) decreased 1.7 percent in the second quarter of 2014, as compared to the second quarter of 2013. We believe the decrease was due primarily to increased conservation efforts by our residential and commercial customer classes, which is driven by the energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.

For the first half of 2014, our consolidated retail electric sales were higher, as compared to the same period in 2013, due primarily to colder weather in the first quarter of 2014. The first half 2014 heating degree days were 12 percent higher in Connecticut, New Hampshire and western Massachusetts and 9 percent higher in the Boston metropolitan area, as compared to the first half of 2013. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the first half of 2013. We believe the decrease was due primarily to an increase in customer conservation efforts as noted above.

For WMECO, fluctuations in retail electric sales do not impact earnings due to the DPU-approved revenue decoupling mechanism. Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4 million, comprised of customer base rate revenues of $125.4 million and a baseline low income discount recovery of $7 million. These two mechanisms effectively break the relationship between sales volume and revenues recognized.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales. In addition, they have benefitted from historically favorable natural gas prices and customer growth across both operating companies. In the second quarter and first half of 2014, consolidated firm natural gas sales, consisting of the firm natural gas sales of Yankee Gas and NSTAR Gas, were higher, as compared to the second quarter and first half of 2013, due primarily to colder weather in the first quarter of 2014, as compared to the same period in 2013, and customer growth in the first half of 2014, as compared to the same period in 2013. The second quarter and first half of 2014 weather-normalized NU consolidated total firm natural gas sales increased 5.3 percent and 4.1 percent, respectively, as compared to the same periods in 2013.

NU Parent and Other Companies: NU parent and other companies, which includes our competitive businesses, had net losses of $1.9 million and $5.2 million in the second quarter and first half of 2014, respectively, compared with earnings of $1.8 million and $7.3 million in the second quarter and first half of 2013, respectively. Excluding the impact of integration costs, NU parent and other companies earned $2.6 million and $5.2 million in the second quarter and first half of 2014, respectively, compared with $3.6 million and $10.8 million in the second quarter and first half of 2013, respectively. The decrease in first half of 2014 earnings was due to the absence of the favorable impact from the resolution of the state income tax audit, which provided a $5.8 million benefit to first half of 2013 earnings.

Liquidity

Consolidated: Cash and cash equivalents totaled $34.1 million as of June 30, 2014, compared with $43.4 million as of December 31, 2013.

On April 15, 2014, NSTAR Electric repaid at maturity the $300 million of 4.875 percent debentures using short-term debt.

On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bonds using short-term debt.

Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their joint $1.45 billion revolving credit facility to extend the expiration date an additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of June 30, 2014 and December 31, 2013, NU had $710.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $739.5 million and $435.5 million of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of June 30, 2014, there were intercompany loans from NU of $6.4 million to CL&P, $95 million to PSNH and $15.9 million to WMECO. As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.

Effective July 23, 2014, NSTAR Electric amended its $450 million revolving credit facility to extend the expiration date an additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014 and December 31, 2013, NSTAR Electric had $194.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5 million and $346.5 million, respectively, of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.

Cash flows provided by operating activities totaled $896.7 million in the first half of 2014, compared with $769 million in the first half of 2013. The improved operating cash flows were due primarily to approximately $126 million in DOE Phase II Damages proceeds received by CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and the decrease of $82.2 million in Pension and PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first half of 2014 ($158 million), as compared to the first half of 2013 ($16 million). For further information on the spent nuclear fuel litigation, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Quarterly Report on Form 10-Q.

On April 7, 2014, Fitch affirmed the corporate credit ratings and outlook of NU, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas. On April 25, 2014, S&P affirmed the corporate credit ratings and revised the outlooks to positive from stable of NU, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas.

In the first half of 2014, CL&P, NSTAR Electric, PSNH, and WMECO paid $85.6 million, $253 million, $33 million, and $49 million, respectively, in common dividends to NU parent.

Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. In the first half of 2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $724 million, $221.4 million, $213.5 million, $117.4 million, and $61.5 million, respectively.

Business Development and Capital Expenditures

Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled $706.2 million in the first half of 2014, compared with $644 million in the first half of 2013. These amounts included $25.5 million and $6.7 million in the first half of 2014 and 2013, respectively, related to our corporate service companies, NUSCO and RRR.

Transmission Business: Overall, transmission business capital expenditures increased by $9.6 million in the first half of 2014, as compared to the first half of 2013. A summary of transmission capital expenditures by company for the first half of 2014 and 2013 is as follows:


	For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013
CL&P	$	111.6	$	84.1
NSTAR Electric		70.2		79.3
PSNH		44.3		35.0
WMECO		33.1		41.5
NPT		12.4		22.1
Total Transmission Segment	$	271.6	$	262.0

NEEWS: GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013. As of June 30, 2014, CL&P and WMECO have placed $638.1 million in service with minimal remaining close-out activities continuing throughout the remainder of 2014.

The Interstate Reliability Project, which includes CL&P's construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid in Rhode Island and Massachusetts, is the second major NEEWS project. As of May 2014, all three states have issued siting approvals. Completing all the project permit requirements, the Army Corps of Engineers issued its permit on the project in the first quarter of 2014. Project construction is underway in all three states. NU's portion of the cost is estimated to be $218 million and construction on its portion of the project is approximately 40 percent complete as of June 30, 2014. The project is expected to be placed in service by the end of 2015.

The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress. The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each of the areas studied and across the interfaces of those areas. These results were presented to the ISO-NE Planning Advisory Committee in November 2013. On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee. These solutions are comprised of many 115 kV upgrades and are expected to cost approximately $350 million and be placed in service in late 2017.

Included as part of NEEWS are associated reliability related projects, $93.1 million of which have been placed in service. As of June 30, 2014, all construction on the associated reliability related projects has been completed.

Through June 30, 2014, CL&P and WMECO capitalized $292 million and $573.4 million, respectively, in costs associated with NEEWS, of which $39.2 million and $6.4 million, respectively, were capitalized in the first half of 2014.

Northern Pass: Northern Pass is NU's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. NPT received ISO-NE approval under Section I.3.9 of the ISO tariff in 2013. By approving the project's Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant adverse effect on the reliability or operating characteristics of the regional energy grid and its participants. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational in the second half of 2017. The DOE continues to work on the draft Environmental Impact Statement (EIS) for Northern Pass. This includes a review of both the recommended route and various alternative routes. We expect the DOE to issue the draft EIS in late 2014. Once it is published, the DOE will commence a process of receiving written and verbal comments on the draft EIS and we expect the issuance of a final EIS in the second half of 2015. We expect to file the state permit application in January 2015 after receipt of the draft EIS.

Greater Boston Reliability and Boston Network Improvements: As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric and PSNH expect to implement a series of new transmission initiatives over the next five years. We expect ISO-NE to select preferred solutions in the second half of 2014, and project costs to be approximately $495 million for these new initiatives.

Distribution Business: A summary of distribution capital expenditures by company for the first half of 2014 and 2013 is as follows:


	For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013
CL&P:
Basic Business	$	24.3	$	27.8
Aging Infrastructure		74.7		71.3
Load Growth		34.7		31.8
Total CL&P		133.7		130.9
NSTAR Electric:
Basic Business		50.2		48.3
Aging Infrastructure		53.1		51.3
Load Growth		14.7		13.4
Total NSTAR Electric		118.0		113.0
PSNH:
Basic Business		14.1		8.5
Aging Infrastructure		26.5		20.0
Load Growth		13.1		10.1
Total PSNH		53.7		38.6
WMECO:
Basic Business		4.5		3.7
Aging Infrastructure		8.1		10.8
Load Growth		2.8		3.3
Total WMECO		15.4		17.8
Total - Electric Distribution (excluding Generation)		320.8		300.3
PSNH Generation		5.2		4.3
WMECO Generation		7.4		0.3
Total - Natural Gas		75.7		70.3
Total Electric and Natural Gas Distribution Segment	$	409.1	$	375.2

For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, distribution substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation additions and expansions.

FERC Regulatory Issues

FERC Base ROE Complaints: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants"). The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets. Complainants sought an order to reduce the base ROE, effective October 1, 2011, and to require refunds. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.

Though NU cannot predict the ultimate outcome of this proceeding, in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's two orders issued on June 19, 2014 for the two refund periods. The aggregate after-tax charge to second quarter 2014 earnings totaled $32.1 million at NU, which represented reserves of $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO.

On July 31, 2014, the Complainants filed an additional complaint with FERC. At this time, the Company cannot determine the outcome of this complaint.

Regulatory Developments and Rate Matters

The Regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs. Other than as described below, for the first half of 2014, changes made to the Regulated companies' rates did not have a material impact on their earnings, financial position, or cash flows. For further information, see "Financial Condition and Business Analysis – Regulatory Developments and Rate Matters" included in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of the NU 2013 Annual Report on Form 10-K.

Connecticut:

Distribution Rates: On June 9, 2014, CL&P filed an application with the PURA to amend customer rates, effective December 1, 2014. CL&P requested an increase in total distribution rates of $231.5 million. The increase includes a base distribution rate increase of $116.7 million, an increase for the annual recovery of $89.5 million of previously approved 2011 and 2012 deferred storm restoration costs totaling $365 million, and an increase of $25.3 million for previously approved electric system resiliency costs. Currently, hearings are scheduled to occur in late August through September, and a final decision is expected in December 2014.

On June 17, 2014, PURA ordered CL&P to use the DOE Phase II Damages proceeds of $65.4 million received on June 1, 2014 to offset the $365 million in 2011 and 2012 deferred storm restoration costs that were approved for recovery by the PURA on March 12, 2014. For further information on the spent nuclear fuel litigation awards, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies." As a result, CL&P will now recover approximately $300 million in storm costs from customers, which will be reflected in final rates approved by PURA at the conclusion of the current CL&P distribution rate case.

New Hampshire:

Generation: In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's ES rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH's generation ownership on the New Hampshire competitive electric market. In a 2013 NHPUC staff report accepted by the NHPUC, the NHPUC staff recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH's generating units, and identify means to mitigate and address stranded cost recovery. In October 2013, the New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH's retail customers for PSNH to divest its interest in generation plants. On November 1, 2013, the Oversight Committee asked for a preliminary report by April 1, 2014 that would include a third party valuation of PSNH's generating assets and a report from NHPUC staff members concerning customers' economic interests in those generating assets.

On April 1, 2014, the NHPUC staff issued a "Preliminary Status Report Addressing the Economic Interest of PSNH's Retail Customers as it Relates to the Potential Divestiture of PSNH's Generating Plants," which included a consultant's analysis of the fair market value of PSNH generating assets and long-term power purchase contracts. The consultant's analysis estimated the fair market value of PSNH's generation assets to be $225 million as of December 31, 2013 and compared that amount to a stated net book value of $660 million, implying potential "stranded costs" in excess of $400 million. NHPUC staff made three recommendations: (1) that any further actions relating to PSNH's generating assets await a final decision in the Clean Air Project (scrubber) prudence proceeding; (2) that existing laws regarding divestiture, energy service, and cost recovery be harmonized; and (3) that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH's coal- and oil-fired electric generating plants.

During its 2014 session, in response to the NHPUC staff report, the House and Senate passed a bill, which enacted changes to the laws governing divestiture of PSNH's generating assets. That bill requires the NHPUC to initiate a proceeding before January 1, 2015, to determine whether all or some of PSNH's generation assets should be divested. A progress report from the NHPUC must be made by March 31, 2015. The bill also changes the law to give the NHPUC express authority to order the divestiture of all or some of PSNH's generation assets if the NHPUC finds it is in the economic interest of customers to do so. The bill also clarifies the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.

In the event of generation asset divestiture or retirement, present law, the PSNH Restructuring Settlement Agreement approved in 2000, and the Bill all require that the NHPUC provide recovery of any stranded costs by PSNH. We continue to believe all costs and generation investments are probable of recovery.

Legislative and Policy Matters

Massachusetts:

Gas Replacement and Expansion: On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure. The program will enable companies, including NSTAR Gas, to better manage the scheduling and costs of replacement. The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies that we believed were the most critical in nature were reported in the NU 2013 Form 10-K. There have been no material changes with regard to these critical accounting policies.

Other Matters

Accounting Standards Recently Adopted: For information regarding new accounting standards, see Note 1B, "Summary of Significant Accounting Policies –Accounting Standards," to the financial statements.

Contractual Obligations and Commercial Commitments: Refer to Note 8B, "Commitments and Contingencies – Long-Term Contractual Arrangements," for discussion of material changes to contractual obligations.

Web Site: Additional financial information is available through our web site at www.nu.com. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10-Q.

RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2014 and 2013:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
							Increase/								Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Operating Revenues			$	1,677.6	$	1,635.9	$	41.7	2.5	%	$	3,968.2	$	3,630.9	$	337.3	9.3	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			624.2		488.3		135.9	27.8			1,602.4		1,236.1		366.3	29.6
	Operations and Maintenance			373.2		357.2		16.0	4.5			724.9		703.3		21.6	3.1
	Depreciation			152.2		159.5		(7.3)	(4.6)			303.0		314.5		(11.5)	(3.7)
	Amortization of Regulatory Assets/(Liabilities), Net			(3.5)		54.6		(58.1)	(a)			54.4		108.6		(54.2)	(49.9)
	Amortization of Rate Reduction Bonds			-		8.1		(8.1)	(100.0)			-		42.6		(42.6)	(100.0)
	Energy Efficiency Programs			102.7		94.1		8.6	9.1			241.5		199.9		41.6	20.8
	Taxes Other Than Income Taxes			134.8		123.5		11.3	9.1			280.3		256.4		23.9	9.3
		Total Operating Expenses		1,383.6		1,285.3		98.3	7.6			3,206.5		2,861.4		345.1	12.1
Operating Income			$	294.0	$	350.6	$	(56.6)	(16.1)	%	$	761.7	$	769.5	$	(7.8)	(1.0)	%

(a)		Percent greater than 100 percent not shown as it is not meaningful.


Operating Revenues
		For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)		2014		2013		Increase/ (Decrease)		Percent		2014		2013		Increase/ (Decrease)		Percent
Electric Distribution		$	1,261.8	$	1,221.6	$	40.2	3.3	%	$	2,847.8	$	2,595.8	$	252.0	9.7	%
Natural Gas Distribution			195.5		154.1		41.4	26.9			628.3		515.9		112.4	21.8
	Total Distribution		1,457.3		1,375.7		81.6	5.9			3,476.1		3,111.7		364.4	11.7
Transmission			206.9		247.9		(41.0)	(16.5)			458.9		487.4		(28.5)	(5.8)
	Total Regulated Companies		1,664.2		1,623.6		40.6	2.5			3,935.0		3,599.1		335.9	9.3
Other and Eliminations			13.4		12.3		1.1	8.9			33.2		31.8		1.4	4.4
Total Operating Revenues		$	1,677.6	$	1,635.9	$	41.7	2.5	%	$	3,968.2	$	3,630.9	$	337.3	9.3	%


A summary of our retail electric sales and firm natural gas sales were as follows:

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
			Increase/
	2014	2013	(Decrease)	Percent		2014	2013	Increase	Percent
Retail Electric Sales in GWh	12,536	12,911	(375)	(2.9)	%	26,884	26,707	177	0.7	%
Firm Natural Gas Sales in Million Cubic Feet	16,924	16,257	667	4.1		63,841	56,872	6,969	12.3

Operating Revenues increased in the second quarter of 2014, as compared to the second quarter of 2013. The increase primarily reflects higher costs associated with purchasing electricity and natural gas on behalf of our customers. Fluctuations in these energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Retail electric sales volumes decreased 2.9 percent from the second quarter of 2013 as a result of milder temperatures in late May and June of 2014, as well as the impact of utility-sponsored energy efficiency programs. Firm natural gas sales volume increased 4.1 percent from the second quarter of 2013 as customer growth and economic conditions in our service territory have shown steady improvement over the past year.

As noted above, our respective utility-sponsored energy efficiency programs have the impact of reducing both retail electric and firm natural gas sales. Certain utility operating companies are permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the second quarter of 2014, base electric and natural gas distribution revenues decreased $3 million, compared to the second quarter of 2013 (including the impact from the recognition of lost base revenues).

Transmission revenues decreased in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to the impact of the reserves recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis.

Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase reflects higher retail electric and firm natural gas sales volumes primarily as a result of the significantly colder weather in the first quarter of 2014, as compared to the same period in 2013, and the overall impact of higher costs associated with the procurement of energy supply. Our energy supply costs were impacted by higher natural gas transportation costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of purchased electric energy for our retail electric customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings.

As noted above, the increase in distribution revenues reflects an increase of approximately 0.7 percent in retail electric sales and 12.3 percent in firm natural gas sales. The increase in sales volumes was driven primarily by the cold winter weather experienced throughout our service territories in the first quarter of 2014. The winter was significantly colder than both normal and the same period last year throughout New England. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the same

period in 2013, reflecting the impact of our utility-sponsored energy efficiency programs. Weather-normalized total firm natural gas sales increased 4.1 percent in the first half of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.

Certain utility operating companies are permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base electric and natural gas distribution revenues increased $38 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).

Transmission revenues decreased in the first half of 2014, as compared to the first half of 2013, due primarily to the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints.

Purchased Power, Fuel and Transmission increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:


	Three Months Ended		Six Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Electric distribution segment fuel and energy supply costs	$	139.6	$	334.7
Firm natural gas sales related costs		35.3		69.2
Transmission segment costs		(0.7)		(3.2)
All other (including eliminations)		3.6		15.7
Partially offset by:
Electric distribution segment purchased power and deferred fuel costs		(41.9)		(50.1)
	$	135.9	$	366.3


	Three Months Ended		Six Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Base Electric Distribution:
Bad debt expense	$	2.0	$	5.2
Implementation of a new outage restoration program at CL&P		3.7		3.8
Employee costs, including pension and benefit related costs		(20.2)		(30.9)
Storm costs		0.4		(4.8)
Other operations and maintenance		7.2		9.1
Total Base Electric Distribution		(6.9)		(17.6)
Total Natural Gas Distribution		(1.1)		3.0
Total Tracked costs (Transmission and Electric Distribution)		14.4		23.5
Total Distribution and Transmission		6.4		8.9
Other and eliminations:
Integration and severance costs		4.7		11.5
All other (including eliminations)		4.9		1.2
Total Operations and Maintenance	$	16.0	$	21.6

The Operations and Maintenance expenses that are recovered through base electric distribution rates (and therefore impact earnings) decreased $6.9 million and $17.6 million, respectively, for the three and six months ended June 30, 2014, as compared to the same periods in 2013. The Operations and Maintenance expenses that are recovered through cost tracking mechanisms (and therefore have no earnings impact) increased $14.4 million and $23.5 million, respectively, for the three and six months ended June 30, 2014, as compared to the same periods in 2013. These increases were primarily driven by an increase in bad debt expense ($4.2 million and $8.2 million, respectively) and higher operation and maintenance costs at the PSNH generation business due to the timing of planned outages ($4.2 million and $5.1 million, respectively) for the three and six months ended June 30, 2014, as compared to the same periods in 2013.

Depreciation decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to a decrease in CYAPC and YAEC decommissioning costs ($12.5 million and $25 million, respectively), partially offset by an increase related to higher utility plant balances resulting from completed construction projects placed into service ($5 million and $10.6 million, respectively).

Amortization of Regulatory Assets/(Liabilities), Net decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:


	Three Months Ended		Six Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Recovery of stranded costs at NSTAR Electric	$	(55.1)	$	(86.4)
Increases in the SCRC, ES and other amortizations at PSNH		(21.5)		(5.8)
Amortization of previously deferred congestion costs at CL&P		19.1		38.3
Other		(0.6)		(0.3)
	$	(58.1)	$	(54.2)

Amortization of Rate Reduction Bonds decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due to the maturity in 2013 of RRBs of NSTAR Electric, PSNH, and WMECO.

Energy Efficiency Programs increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO and expanded energy conservation programs at CL&P in 2014, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric. All costs are fully recovered through approved tracking mechanisms and therefore do not impact earnings.

Taxes Other Than Income Taxes increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes ($9.1 million and $16.6 million, respectively) as a result of both an increase in utility plant balances and property tax rates, and an increase in the Connecticut gross earnings tax ($2.2 million and $8.2 million, respectively) attributable to an increase in retail revenues.

Interest Expense increased $5.6 million and $19.4 million for the three and six months ended June 30, 2014, as compared to the same periods in 2013, respectively, due primarily to the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in the first quarter of 2013 ($8.8 million for the six months), lower interest income on deferred transition costs ($3.5 million and $8 million, respectively), and an increase in interest on long-term debt ($1.5 million and $3.6 million, respectively) as a result of new debt issuances in the second quarter and first half of 2014.

Other Income, Net decreased $5.5 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($5.3 million).

Income Tax Expense


	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Decrease		Percent		2014		2013		Increase		Percent
Income Tax Expense	$	77.8	$	95.6	$	(17.8)	(18.6)	%	$	219.3	$	216.1	$	3.2	1.5	%

Income Tax Expense decreased for the three months ended June 30, 2014, as compared to the same period in 2013, due primarily to lower pre-tax earnings ($2.5 million) and the tax benefit impact from the reserve recorded in the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.1 million), partially offset by higher state taxes ($4.6 million) and various other tax impacts ($2.2 million).

Income Tax Expense increased for the six months ended June 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($10.6 million), higher state taxes ($8.6 million), the absence of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($4.8 million), and various other tax impacts ($1.3 million), partially offset by the tax benefit impact from the reserve recorded as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.1 million).

RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY

The following provides the amounts and variances in operating revenues and expense line items for the condensed statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2014 and 2013:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)			2014		2013		Increase/ (Decrease)		Percent		2014		2013		Increase/ (Decrease)		Percent
Operating Revenues			$	587.3	$	569.3	$	18.0	3.2	%	$	1,321.9	$	1,193.4	$	128.5	10.8	%
Operating Expenses:
	Purchased Power and Transmission			199.8		184.8		15.0	8.1			481.2		414.1		67.1	16.2
	Operations and Maintenance			131.8		123.8		8.0	6.5			241.3		232.6		8.7	3.7
	Depreciation			46.6		45.1		1.5	3.3			92.7		87.6		5.1	5.8
	Amortization of Regulatory Assets, Net			19.6		0.5		19.1	(a)			49.5		11.2		38.3	(a)
	Energy Efficiency Programs			35.3		20.8		14.5	69.7			78.0		43.7		34.3	78.5
	Taxes Other Than Income Taxes			62.1		57.5		4.6	8.0			129.1		117.7		11.4	9.7
		Total Operating Expenses		495.2		432.5		62.7	14.5			1,071.8		906.9		164.9	18.2
Operating Income			$	92.1	$	136.8	$	(44.7)	(32.7)	%	$	250.1	$	286.5	$	(36.4)	(12.7)	%

(a) Percent greater than 100 percent not shown as it is not meaningful.


Operating Revenues
CL&P's retail sales were as follows:
	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2014	2013	Decrease	Percent		2014	2013	Increase	Percent
Retail Sales in GWh	5,050	5,194	(144)	(2.8)	%	10,999	10,875	124	1.1	%

CL&P's Operating Revenues increased in the second quarter of 2014, as compared to the same period of 2013. The increase primarily reflects higher costs associated with purchasing electricity on behalf of our customers. Fluctuations in these energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis. In addition, retail sales volumes decreased 2.8 percent in the second quarter of 2014, as compared to the same period in 2013, as a result of milder temperatures in late May and June of 2014.

CL&P's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase reflects higher retail sales volumes of 1.1 percent as a result of significantly colder weather in the first quarter of 2014, as compared to the same period in 2013, and the overall impact of higher costs associated with the procurement of energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints.

Purchased Power and Transmission increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:


	Three Months Ended		Six Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
GSC Supply Costs	$	3.2	$	104.4
Transmission Costs		5.4		11.8
Deferred Fuel Costs		26.8		(29.0)
Purchased Power Costs		(15.6)		(15.2)
Other		(4.8)		(4.9)
	$	15.0	$	67.1

The increase in GSC supply costs was due primarily to higher average supply prices and an increase in GSC loads as a result of an increase in retail sales and customers returning to standard offer from third party suppliers. On July 1, 2013, CL&P began to procure approximately 30 percent of GSC load. Costs associated with the remaining 70 percent of the GSC load are the contractual amounts CL&P must pay to various energy suppliers that have been awarded the right to supply standard service and supplier of last resort service load through a competitive solicitation process. The increase in transmission costs was the result of an increase in the retail transmission deferral, which reflects the actual costs of transmission service compared to estimated billed amounts. The decrease in deferred fuel costs for the six months ended June 30, 2014 was due primarily to higher average electric supply prices, as compared to the prices projected when standard service rates were set. Purchased Power and Transmission costs are included in PURA-approved tracking mechanisms and do not impact earnings.

Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the second quarter of 2014, as compared to the same period in 2013, driven by a $5.2 million increase in tracked costs that have no earnings impact, which was primarily attributable to higher bad debt expense of $3.6 million. There was also an increase in costs that impact earnings of $2.8 million, which was primarily attributable to the implementation of a new outage restoration program of $3.7 million, higher routine vegetation management costs of $3.7 million and higher bad debt expense of $1.3 million, partially offset by lower employee costs (including pension and benefit related costs) of $8.4 million.

Operations and Maintenance increased in the first half of 2014, as compared to the same period in 2013, driven by a $9.6 million increase in costs that have no earnings impact, primarily attributable to higher bad debt expense of $7.2 million. Partially offsetting this increase was a decrease in costs that impact earnings of $0.9 million, primarily attributable to lower employee costs (including pension and benefit related costs) of $13.1 million, partially offset by the implementation of a new outage restoration program of $3.8 million, higher bad debt expense of $2.9 million and higher routine vegetation management costs of $3.4 million.

Depreciation increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in amortization expense related to previously deferred congestion charges.

Energy Efficiency Programs increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to expanded energy conservation programs in 2014. All costs are fully recovered through PURA-approved tracking mechanisms and therefore do not impact earnings.

Taxes Other Than Income Taxes increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates ($3.9 million and $7.8 million, respectively). In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in retail revenues ($1.1 million and $4.7 million, respectively).

Interest Expense increased $3.5 million and $8 million for the three and six months ended June 30, 2014, as compared to the same periods in 2013, respectively, due primarily to the absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($6 million for the six months), an increase in other interest ($1 million and $2.2 million, respectively) and an increase in interest on long-term debt ($2 million and $2.2 million, respectively).

Other Income, Net decreased $2.9 million in the first six months of 2014, as compared to the same period in 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($1.4 million) and lower AFUDC-Equity ($1.2 million).

Income Tax Expense


	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Decrease		Percent		2014		2013		Decrease		Percent
Income Tax Expense	$	20.4	$	37.8	$	(17.4)	(46.0)	%	$	65.9	$	77.0	$	(11.1)	(14.4)	%

Income Tax Expense decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to lower pre-tax earnings ($5.8 million and $4.2 million, respectively) and the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($12.8 million for the three and six months), partially offset by the absence in 2014 of the state audit closure benefit impact ($2.9 million for the six months) and various other tax impacts ($1.2 million and $3.0 million, respectively).

EARNINGS SUMMARY


	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Decrease		Percent		2014		2013		Decrease		Percent
Net Income	$	37.4	$	67.9	$	(30.5)	(44.9)	%	$	116.7	$	152.9	$	(36.2)	(23.7)	%

CL&P's second quarter 2014 earnings were lower than the same period in 2013 due primarily to the establishment of an $18.5 million after-tax reserve related to the June 2014 FERC ROE orders, lower retail sales as a result of milder temperatures in late May and June of 2014, as compared to the same period in 2013, higher property tax expense, increased interest expense relating to an April 2014 financing, and higher depreciation expense. Partially offsetting these unfavorable earnings impacts were increased investments in the transmission infrastructure.

For the six months ended June 30, 2014, CL&P's earnings decreased, as compared to the same period in 2013, due primarily to the establishment of the after-tax reserve related to the June 2014 FERC ROE orders, higher property tax expense and increased interest expense relating to an April 2014 financing. Partially offsetting these unfavorable earnings impacts were higher retail electric sales as a result of colder weather in the first quarter of 2014 and increased investments in the transmission infrastructure.

LIQUIDITY

CL&P had cash flows provided by operating activities of $275.4 million in the first half of 2014, compared with $178.2 million in the first half of 2013. The improved cash flows were due primarily to $65.4 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and an increase in regulatory overrecoveries, partially offset by income tax payments of $3.8 million in the first half of 2014, as compared to income tax refunds of $6 million in the first half of 2013, and an unfavorable cash flow impact relating to the timing of accounts receivable payments made to affiliated companies in the second quarter of 2014.

Effective July 23, 2014, NU parent and certain of its subsidiaries, including CL&P, amended their joint $1.45 billion revolving credit facility to extend the expiration date an additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt to its subsidiaries, including CL&P. As of June 30, 2014 and December 31, 2013, there were intercompany loans from NU parent of $6.4 million and $287.3 million, respectively, to CL&P.

Additional financing activities in the first half of 2014 included $85.6 million in common stock dividends paid to NU parent.

On April 7, 2014, Fitch affirmed the corporate credit rating and outlook of CL&P. On April 25, 2014, S&P affirmed the corporate credit rating and revised the outlook to positive from stable of CL&P.

RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY

The following provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NSTAR Electric included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:


			Operating Revenues and Expenses
			For the Six Months Ended June 30,
(Millions of Dollars)			2014		2013		Increase/		Percent
(Millions of Dollars)			2014		2013		(Decrease)		Percent
Operating Revenues			$	1,227.7	$	1,162.7	$	65.0	5.6	%
Operating Expenses:
	Purchased Power and Transmission			562.0		403.9		158.1	39.1
	Operations and Maintenance			164.9		180.2		(15.3)	(8.5)
	Depreciation			93.6		90.9		2.7	3.0
	Amortization of Regulatory Assets, Net			14.1		100.5		(86.4)	(86.0)
	Amortization of Rate Reduction Bonds			-		15.0		(15.0)	(100.0)
	Energy Efficiency Programs			88.6		102.4		(13.8)	(13.5)
	Taxes Other Than Income Taxes			64.6		62.7		1.9	3.0
		Total Operating Expenses		987.8		955.6		32.2	3.4
Operating Income			$	239.9	$	207.1	$	32.8	15.8	%


Operating Revenues
NSTAR Electric's retail sales were as follows:

	For the Six Months Ended June 30,
	2014	2013	Decrease	Percent
Retail Sales in GWh	10,183	10,198	(15)	(0.1)	%

NSTAR Electric's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply. Our energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis. Additionally, stranded cost recovery revenues decreased during the period, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs. Base distribution revenues were relatively flat in the first half of 2014, as compared to the same period in 2013, reflecting comparable sales, which was due primarily to colder weather in the first quarter of 2014 offset by milder temperatures in late May and June of 2014 and customer savings due to the impact of its energy efficiency programs. NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base distribution revenues increased $5.4 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).

Purchased Power and Transmission increased in the first half of 2014, as compared to the first half of 2013, due primarily to the following:


(Millions of Dollars)	Six Months Ended Increase/(Decrease)
Basic Service Costs	$	115.4
Transmission Costs		26.4
Purchased Power Costs		20.1
Deferred Fuel Costs		(3.8)
	$	158.1

The increase in Basic Service costs was primarily related to higher average supply prices. The increase in transmission costs was due primarily to higher RNS expense, and the increase in purchased power costs was due primarily to higher congestion charges. The decrease in deferred fuel costs was due primarily to higher average electricity supply prices, as compared to the prices projected when Basic Service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.

Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance decreased in the first half of 2014, as compared to the first half of 2013, driven by a $21.5 million reduction in costs that impact earnings (primarily attributable to lower employee costs and benefit costs of $15.7 million and lower storm costs of $3 million. Partially offsetting this decrease was an increase in costs that have no earnings impact of $6.2 million (primarily attributable to higher storm costs of $3 million).

Depreciation increased in the first half of 2014, as compared to the first half of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net decreased in the first half of 2014, as compared to the first half of 2013, due primarily to a decrease in the recovery of previously deferred stranded costs.

Amortization of Rate Reduction Bonds decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in March 2013.

Energy Efficiency Programs decreased in the first half of 2014, as compared to the first half of 2013, due primarily to a decrease in the amortization of previously deferred costs. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.

Taxes Other Than Income Taxes increased in the first half of 2014, as compared to the first half of 2013, due to an increase in property taxes as a result of an increase in utility plant balances, partially offset by lower average municipal property tax rates.

Interest Expense increased $8.6 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower interest income on deferred transition costs ($8 million), as well as an increase in interest on long-term debt.

Other Income/(Loss), Net decreased $1.4 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans.

Income Tax Expense


	For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Increase		Percent
Income Tax Expense	$	79.7	$	68.9	$	10.8	15.7	%

Income Tax Expense increased in the first half of 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($11.6 million) and higher state taxes ($3.5 million), partially offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($4.1 million).

EARNINGS SUMMARY


	For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Increase		Percent
Net Income	$	118.2	$	106.2	$	12.0	11.3	%

In the first half of 2014, NSTAR Electric's earnings increased, as compared to the same period in 2013, due primarily to lower operations and maintenance expenses attributed to lower employee costs, benefit costs and lower storm costs. Partially offsetting these favorable earnings impacts were the establishment of a $6.1 million after-tax reserve related to the June 2014 FERC ROE orders and higher depreciation and property tax expenses.

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities of $387.7 million in the first half of 2014, compared with $91.6 million in the first half of 2013. The increase in operating cash flows was due primarily to the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard, the timing of collections of accounts receivables from affiliated companies, $29.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, a decrease in income tax payments in the first half of 2014, as compared to the first half of 2013, and the absence of Pension Plan cash contributions in the first half of 2014, as compared to the first half of 2013. These favorable cash flow impacts were partially offset by the absence of costs recovered in rates related to the RRBs that were fully amortized in the first quarter of 2013.

Effective July 23, 2014, NSTAR Electric amended its $450 million revolving credit facility to extend the expiration date an additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014 and December 31, 2013, NSTAR Electric had $194.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5 million and $346.5 million, respectively, of available borrowing capacity. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.

RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

The following provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for PSNH included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:


			Operating Revenues and Expenses
			For the Six Months Ended June 30,
							Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent
Operating Revenues			$	511.5	$	489.9	$	21.6	4.4	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			183.6		151.1		32.5	21.5
	Operations and Maintenance			132.5		122.1		10.4	8.5
	Depreciation			48.7		45.5		3.2	7.0
	Amortization of Regulatory Assets/(Liabilities), Net			(7.8)		(2.0)		(5.8)	(a)
	Amortization of Rate Reduction Bonds			-		19.8		(19.8)	(100.0)
	Energy Efficiency Programs			7.1		7.1		-	-
	Taxes Other Than Income Taxes			34.3		33.9		0.4	1.2
		Total Operating Expenses		398.4		377.5		20.9	5.5
Operating Income			$	113.1	$	112.4	$	0.7	0.6	%

(a) Percent greater than 100 percent not shown as it is not meaningful.


Operating Revenues
PSNH's retail sales were as follows:
	For the Six Months Ended June 30,
	2014	2013	Increase	Percent
Retail Sales in GWh	3,909	3,837	72	1.9	%

PSNH's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase of 1.9 percent in retail sales as a result of the colder weather in the first quarter of 2014, as compared to the same period in 2013. The average daily temperature in New Hampshire in the first quarter of 2014 was over five degrees lower than the first quarter of 2013. In addition, revenues increased due to the overall impact of higher costs associated with the procurement of energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Also reflected in the revenue increase were increases of $6.4 million related to NHPUC-approved distribution rate increases effective July 1, 2013 and increases in transmission revenues as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure, partially offset by the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis.

Purchased Power, Fuel and Transmission increased in the first half of 2014, as compared to the first half of 2013, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Generation Fuel Costs	$	35.2
Renewable Energy Costs		9.9
Transmission Costs		4.7
Purchased Power Costs		(19.2)
Other		1.9
	$	32.5

The increase in generation fuel costs was due primarily to an increase in the amount of electricity generated by PSNH facilities. The increase in renewable energy costs was a result of lower regional greenhouse gas initiative auction proceeds, partially offset by lower renewable energy requirements set by the NHPUC. The increase in transmission costs was as a result of an increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. The decrease in purchased power costs was a result of additional customer migration to third party suppliers. Purchased Power, Fuel and Transmission costs are included in NHPUC-approved tracking mechanisms and do not impact earnings.

Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half of 2014, as compared to the first half of 2013, driven by an $8 million increase in costs that have no earnings impact (primarily attributable to higher operations and maintenance costs at the generation business of $5.1 million due to the timing of planned outages and higher bad debt expense of $1 million, partially offset by lower employee costs, including pension and benefit related costs, of $2.4 million). Additionally, there was an increase in costs that impact earnings of $2.4 million.

Amortization of Regulatory Assets/(Liabilities), Net increased in the first half of 2014, as compared to the first half of 2013, due primarily to increases in the stranded cost recovery charge, default energy service, and other amortizations of $1.7 million, $0.2 million, and $3.9 million, respectively.

Amortization of Rate Reduction Bonds decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in May 2013.

Income Tax Expense


	For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Change		Percent
Income Tax Expense	$	34.6	$	34.6	$	-	-	%

Income Tax Expense was relatively flat in the first half of 2014, as compared to the first half of 2013, due primarily to higher pre-tax earnings ($1.5 million), offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($1.5 million).

EARNINGS SUMMARY


	For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Increase		Percent
Net Income	$	56.7	$	56.2	$	0.5	0.1	%

In the first half of 2014, PSNH's earnings increased, as compared to the same period in 2013, due primarily to higher distribution retail revenues, which were favorably impacted by the PSNH annualized distribution rate increases effective July 1, 2013, and higher retail electric sales. Partially offsetting these favorable earnings impacts were the establishment of a $2 million after-tax reserve related to the June 2014 FERC ROE orders, and higher depreciation expense.

LIQUIDITY

PSNH had cash flows provided by operating activities of $142.4 million in the first half of 2014, compared with $138.7 million in the first half of 2013. The improved cash flows were due to $13.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of approximately $45 million in NUSCO Pension Plan cash contributions in the first half of 2014, and the favorable impact of the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2013. These favorable cash flow impacts were partially offset by income tax payments of $28.8 million in the first half of 2014, compared with income tax refunds of $12.1 million in the first half of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013.

RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY

The following provides the amounts and variances in operating revenues and expense line items for the condensed statements of income for WMECO included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:


			Operating Revenues and Expenses
			For the Six Months Ended June 30,
							Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent
Operating Revenues			$	245.7	$	240.0	$	5.7	2.4	%
Operating Expenses:
	Purchased Power and Transmission			87.1		72.3		14.8	20.5
	Operations and Maintenance			46.3		44.1		2.2	5.0
	Depreciation			20.6		18.3		2.3	12.6
	Amortization of Regulatory Assets, Net			0.7		0.8		(0.1)	(12.5)
	Amortization of Rate Reduction Bonds			-		7.8		(7.8)	(100.0)
	Energy Efficiency Programs			22.1		16.2		5.9	36.4
	Taxes Other Than Income Taxes			16.5		12.5		4.0	32.0
		Total Operating Expenses		193.3		172.0		21.3	12.4
Operating Income			$	52.4	$	68.0	$	(15.6)	(22.9)	%


Operating Revenues
WMECO's retail sales were as follows:
	For the Six Months Ended June 30,
	2014	2013	Decrease	Percent
Retail Sales in GWh	1,793	1,798	(5)	(0.2)	%

WMECO's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013, due primarily to a $3.9 million increase in revenues that impacts earnings due to the reversal of a previously established wholesale billing adjustment. The remaining increase primarily reflects a higher level of recovery related to WMECO's energy supply and energy efficiency programs. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis. Base distribution revenues were relatively flat in the first half of 2014, as compared to the same period in 2013. Fluctuations in WMECO's kWh sales have no impact on earnings, as its revenues are decoupled from sales volumes and changes in revenues are primarily related to changes in its cost tracking mechanisms.

Purchased Power and Transmission increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in supplier contract prices and an increase in customers returning to default service from third party suppliers ($13.9 million) and an increase in transmission costs ($5.7 million) as a result of an increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. Partially offsetting this increase was the impact of the change in deferred fuel costs ($2.4 million) due primarily to higher average electric supply prices, as compared to the prices projected when basic service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.

Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half of 2014, as compared to the first half of 2013, driven by a $2.5 million increase in costs that impact earnings (primarily attributable to an increase in workers' compensation claims of $1.9 million and higher bad debt expense of $0.8 million). Partially offsetting this increase was a decrease in costs that have no earnings impact of $0.3 million.

Amortization of Rate Reduction Bonds decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in June 2013.

Energy Efficiency Programs increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.

Taxes Other Than Income Taxes increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.

Income Tax Expense


	For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Decrease		Percent
Income Tax Expense	$	16.1	$	21.8	$	(5.7)	(26.1)	%

Income Tax Expense decreased in the first half of 2014, as compared to the first half of 2013, due primarily to the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($3.6 million) and lower pre-tax earnings ($2.3 million).

EARNINGS SUMMARY


	For the Six Months Ended June 30,
(Millions of Dollars)	2014		2013		Decrease		Percent
Net Income	$	25.1	$	35.0	$	(9.9)	(28.3)	%

In the first half of 2014, WMECO's earnings decreased, as compared to the same period in 2013, due primarily to the establishment of a $5.5 million after-tax reserve related to the June 2014 FERC ROE orders, an increase in workers' compensation claims, and higher depreciation and property tax expense. Partially offsetting these unfavorable earnings impacts were an increase in generation earnings and a decrease in other interest expense.

LIQUIDITY

WMECO had cash flows provided by operating activities of $96.6 million in the first half of 2014, compared with $119.3 million in the first half of 2013. The decrease in operating cash flows was due primarily to income tax payments of $16.9 million in the first half of 2014, compared with income tax refunds of $32.4 million in the first half of 2013 and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013, partially offset by the receipt of $18.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation and an increase in regulatory overrecoveries.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Information

Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. NU's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large scale energy related transactions entered into by its Regulated companies.

Other Risk Management Activities

Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.

Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

If the respective unsecured debt ratings of NU or its subsidiaries were reduced to below investment grade by either Moody's or S&P, certain of NU's contracts would require additional collateral in the form of cash to be provided to counterparties and independent system operators. NU would have been and remains able to provide that collateral.

For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 4, "Derivative Instruments," to the financial statements.

We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in NU's 2013 Form 10-K, which is incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in the NU 2013 Form 10-K.

ITEM 4.

CONTROLS AND PROCEDURES

Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of June 30, 2014 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, NSTAR Electric, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

We are parties to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our 2013 Form 10-K, which disclosures are incorporated herein by reference. There have been no additional material legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our 2013 Form 10-K.

ITEM 1A.

RISK FACTORS

We are subject to a variety of significant risks in addition to the matters set forth under "Forward-Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q. We have identified a number of these risk factors in Part I, Item 1A, "Risk Factors," in our 2013 Form 10-K, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our 2013 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to the Company's Long-Term Incentive Plans.


Period	Total Number of Shares Purchased		Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)
April 1 – April 30, 2014	-	$	-	-	-
May 1 – May 31, 2014	-		-	-	-
June 1 – June 30, 2014	208,608		46.93	-	-
Total	208,608	$	46.93	-	-

ITEM 6.

EXHIBITS

Each document described below is filed herewith, unless designated with an asterisk (*), which exhibits are incorporated by reference by the registrant under whose name the exhibit appears.


Exhibit No.		Description

Listing of Exhibits (NU)

12		Ratio of Earnings to Fixed Charges

31		Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

31.1		Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

32		Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, and James J. Judge, Executive Vice President and Chief Financial Officer of NU, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

Listing of Exhibits (CL&P)

*4.1		Supplemental Indenture (2014 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2014 (Exhibit 4.1, CL&P Current Report on Form 8-K filed April 29, 2014, File No. 000-00404)

12		Ratio of Earnings to Fixed Charges

31		Certification of Leon J. Olivier, Chief Executive Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

31.1		Certification of James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

32		Certification of Leon J. Olivier, Chief Executive Officer of CL&P, and James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

Listing of Exhibits (NSTAR Electric)

12		Ratio of Earnings to Fixed Charges

31		Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

31.1		Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

32		Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014


Listing of Exhibits (PSNH)

12		Ratio of Earnings to Fixed Charges

31		Certification of Leon J. Olivier, Chief Executive Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

31.1		Certification of James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

32		Certification of Leon J. Olivier, Chief Executive Officer of PSNH, and James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

Listing of Exhibits (WMECO)

12		Ratio of Earnings to Fixed Charges

31		Certification of Leon J. Olivier, Chief Executive Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

31.1		Certification of James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

32		Certification of Leon J. Olivier, Chief Executive Officer of WMECO, and James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

Listing of Exhibits (NU, CL&P, NSTAR Electric, PSNH, WMECO)


101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema

101.CAL	XBRL Taxonomy Extension Calculation

101.DEF	XBRL Taxonomy Extension Definition

101.LAB	XBRL Taxonomy Extension Labels

101.PRE	XBRL Taxonomy Extension Presentation

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.






	NORTHEAST UTILITIES

August 1, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE






	THE CONNECTICUT LIGHT AND POWER COMPANY

August 1, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE






	NSTAR ELECTRIC COMPANY

August 1, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE






	PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

August 1, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE






	WESTERN MASSACHUSETTS ELECTRIC COMPANY

August 1, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer