CONNECTICUT LIGHT & POWER CO - Quarter Report: 2014 September (Form 10-Q)

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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 September 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 registrants were 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 October 31, 2014
Northeast Utilities Common shares, $5.00 par value	316,799,371 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
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 oxides
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 Income	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 Subs idiaries	40
The Connecticut Light and Power Company	54
NSTAR Electric Company and Subsidiary	57
Public Service Company of New Hampshire and Subsidiary	59
Western Massachusetts Electric Company	61

ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk	63

ITEM 4 – Controls and Procedures	63

PART II – OTHER INFORMATION

ITEM 1 – Legal Proceedings	64

ITEM 1A – Risk Factors	64

ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds	64

ITEM 6 – Exhibits	65

SIGNATURES	67

iii


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


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

ASSETS

Current Assets:
	Cash and Cash Equivalents	$	41,706	$	43,364
	Receivables, Net		848,510		765,391
	Unbilled Revenues		181,284		224,982
	Fuel, Materials and Supplies		333,869		303,233
	Regulatory Assets		445,962		535,791
	Marketable Securities		114,722		92,427
	Prepayments and Other Current Assets		135,497		121,861
Total Current Assets			2,101,550		2,087,049

Property, Plant and Equipment, Net			18,254,610		17,576,186

Deferred Debits and Other Assets:
	Regulatory Assets		3,241,122		3,758,694
	Goodwill		3,519,401		3,519,401
	Marketable Securities		518,032		488,515
	Other Long-Term Assets		347,596		365,692
Total Deferred Debits and Other Assets			7,626,151		8,132,302



Total Assets		$	27,982,311	$	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)


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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable		$	1,046,961	$	1,093,000
	Long-Term Debt - Current Portion			245,583		533,346
	Accounts Payable			608,639		742,251
	Regulatory Liabilities			398,985		204,278
	Other Current Liabilities			629,508		702,776
Total Current Liabilities				2,929,676		3,275,651

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			4,257,996		4,029,026
	Regulatory Liabilities			509,889		502,984
	Derivative Liabilities			420,931		624,050
	Accrued Pension, SERP and PBOP			787,550		896,844
	Other Long-Term Liabilities			863,164		923,053
Total Deferred Credits and Other Liabilities				6,839,530		6,975,957

Capitalization:
	Long-Term Debt			8,166,985		7,776,833

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

	Equity:
	Common Shareholders' Equity:
		Common Shares		1,666,767		1,665,351
		Capital Surplus, Paid In		6,219,516		6,192,765
		Retained Earnings		2,351,421		2,125,980
		Accumulated Other Comprehensive Loss		(40,172)		(46,031)
		Treasury Stock		(306,980)		(326,537)
	Common Shareholders' Equity			9,890,552		9,611,528
Total Capitalization				18,213,105		17,543,929

Total Liabilities and Capitalization			$	27,982,311	$	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 September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars, Except Share Information)				2014		2013		2014		2013

Operating Revenues				$	1,892,532	$	1,892,590	$	5,860,736	$	5,523,475

Operating Expenses:
	Purchased Power, Fuel and Transmission				716,631		645,881		2,318,993		1,881,992
	Operations and Maintenance				344,092		386,700		1,069,015		1,089,960
	Depreciation				153,210		149,105		456,224		463,635
	Amortization of Regulatory Assets/(Liabilities), Net				(22,531)		70,046		31,826		178,668
	Amortization of Rate Reduction Bonds				-		-		-		42,581
	Energy Efficiency Programs				118,693		106,097		360,228		306,010
	Taxes Other Than Income Taxes				141,527		135,499		421,862		391,846
			Total Operating Expenses		1,451,622		1,493,328		4,658,148		4,354,692
Operating Income					440,910		399,262		1,202,588		1,168,783

Interest Expense:
	Interest on Long-Term Debt				85,208		84,911		260,076		256,205
	Other Interest				4,530		2,565		12,132		(5,622)
		Interest Expense			89,738		87,476		272,208		250,583
Other Income, Net					11,860		8,945		19,054		21,655
Income Before Income Tax Expense					363,032		320,731		949,434		939,855
Income Tax Expense					126,539		109,351		345,858		325,442
Net Income					236,493		211,380		603,576		614,413
Net Income Attributable to Noncontrolling Interests					1,879		1,879		5,639		5,803
Net Income Attributable to Controlling Interest				$	234,614	$	209,501	$	597,937	$	608,610

Basic and Diluted Earnings Per Common Share				$	0.74	$	0.66	$	1.89	$	1.93

Dividends Declared Per Common Share				$	0.39	$	0.37	$	1.18	$	1.10

Weighted Average Common Shares Outstanding:
	Basic				316,340,691		315,291,346		315,941,904		315,191,752
	Diluted				317,554,925		316,218,239		317,186,490		316,061,131


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



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income				$	236,493	$	211,380	$	603,576	$	614,413
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments				509		509		1,528		1,539
	Changes in Unrealized Gains/(Losses) on Other Securities				(216)		(38)		242		(810)
	Changes in Funded Status of Pension, SERP and PBOP Benefit Plans				1,042		1,611		4,089		4,738
Other Comprehensive Income, Net of Tax					1,335		2,082		5,859		5,467
Comprehensive Income Attributable to Noncontrolling Interests					(1,879)		(1,879)		(5,639)		(5,803)
Comprehensive Income Attributable to Controlling Interest				$	235,949	$	211,583	$	603,796	$	614,077


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 Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013

Operating Activities:
	Net Income		$	603,576	$	614,413
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		456,224		463,635
		Deferred Income Taxes		64,755		334,225
		Pension, SERP and PBOP Expense		74,296		146,803
		Pension and PBOP Contributions		(74,681)		(338,301)
		Regulatory Overrecoveries, Net		290,111		66,239
		Amortization of Regulatory Assets, Net		31,826		178,668
		Amortization of Rate Reduction Bonds		-		42,581
		Proceeds from DOE Damages Claim, Net		132,138		-
		Other		(17,096)		3,158
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(66,463)		(98,432)
		Fuel, Materials and Supplies		(27,147)		(13,134)
		Taxes Receivable/Accrued, Net		26,533		(28,609)
		Accounts Payable		(69,448)		(112,512)
		Other Current Assets and Liabilities, Net		(20,607)		(81,766)
Net Cash Flows Provided by Operating Activities				1,404,017		1,176,968

Investing Activities:
	Investments in Property, Plant and Equipment			(1,117,493)		(1,073,759)
	Proceeds from Sales of Marketable Securities			388,352		487,729
	Purchases of Marketable Securities			(389,406)		(541,070)
	Decrease in Special Deposits			-		69,259
	Other Investing Activities			(4,669)		(1,137)
Net Cash Flows Used in Investing Activities				(1,123,216)		(1,058,978)

Financing Activities:
	Cash Dividends on Common Shares			(356,080)		(341,720)
	Cash Dividends on Preferred Stock			(5,639)		(5,802)
	Increase/(Decrease) in Notes Payable			6,000		(172,000)
	Issuance of Long-Term Debt			650,000		1,350,000
	Retirements of Long-Term Debt			(576,650)		(840,600)
	Retirements of Rate Reduction Bonds			-		(82,139)
	Other Financing Activities			(90)		(13,536)
Net Cash Flows Used in Financing Activities				(282,459)		(105,797)
Net (Decrease)/Increase in Cash and Cash Equivalents				(1,658)		12,193
Cash and Cash Equivalents - Beginning of Period				43,364		45,748
Cash and Cash Equivalents - End of Period			$	41,706	$	57,941

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


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


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

ASSETS

Current Assets:
	Cash	$	16,294	$	7,237
	Receivables, Net		369,492		319,670
	Accounts Receivable from Affiliated Companies		35,276		13,777
	Unbilled Revenues		87,806		92,401
	Regulatory Assets		116,531		150,943
	Materials and Supplies		47,086		54,606
	Accumulated Deferred Income Taxes		52,839		-
	Prepaid Property Taxes		47,429		13,962
	Prepayments and Other Current Assets		17,608		39,120
Total Current Assets			790,361		691,716

Property, Plant and Equipment, Net			6,700,798		6,451,259

Deferred Debits and Other Assets:
	Regulatory Assets		1,369,025		1,663,147
	Other Long-Term Assets		178,313		174,380
Total Deferred Debits and Other Assets			1,547,338		1,837,527



Total Assets		$	9,038,497	$	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)


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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to NU Parent		$	105,400	$	287,300
	Long-Term Debt - Current Portion			162,000		150,000
	Accounts Payable			228,379		201,047
	Accounts Payable to Affiliated Companies			46,977		56,531
	Obligations to Third Party Suppliers			67,630		73,914
	Accrued Taxes			54,652		37,186
	Regulatory Liabilities			195,663		93,961
	Derivative Liabilities			86,759		92,233
	Other Current Liabilities			107,284		97,530
Total Current Liabilities				1,054,744		1,089,702

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,581,344		1,510,586
	Regulatory Liabilities			87,696		93,757
	Derivative Liabilities			418,137		617,072
	Accrued Pension, SERP and PBOP			63,756		95,895
	Other Long-Term Liabilities			143,838		163,588
Total Deferred Credits and Other Liabilities				2,294,771		2,480,898

Capitalization:
	Long-Term Debt			2,679,775		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		1,804,228		1,682,047
		Retained Earnings		1,029,473		961,482
		Accumulated Other Comprehensive Loss		(1,046)		(1,387)
	Common Stockholder's Equity			2,893,007		2,702,494
Total Capitalization				5,688,982		5,409,902

Total Liabilities and Capitalization			$	9,038,497	$	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 September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013			2014		2013

Operating Revenues			$	695,642	$	648,420	$	2,017,580	$	1,841,846

Operating Expenses:
	Purchased Power and Transmission			255,787		253,152		736,952		667,266
	Operations and Maintenance			127,285		127,104		368,562		359,759
	Depreciation			46,886		44,786		139,598		132,356
	Amortization of Regulatory Assets/(Liabilities), Net			13,098		(27)		62,644		11,223
	Energy Efficiency Programs			41,399		24,544		119,389		68,211
	Taxes Other Than Income Taxes			64,994		64,979		194,105		182,676
		Total Operating Expenses		549,449		514,538		1,621,250		1,421,491
Operating Income				146,193		133,882		396,330		420,355

Interest Expense:
	Interest on Long-Term Debt			34,743		32,845		102,290		98,163
	Other Interest			3,992		2,439		8,158		801
		Interest Expense		38,735		35,284		110,448		98,964
Other Income, Net				6,456		3,861		10,658		10,946
Income Before Income Tax Expense				113,914		102,459		296,540		332,337
Income Tax Expense				30,038		36,136		95,980		113,149
Net Income			$	83,876	$	66,323	$	200,560	$	219,188



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





CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income			$	83,876	$	66,323	$	200,560	$	219,188
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			111		111		333		333
	Changes in Unrealized Gains/(Losses) on Other Securities			(7)		(1)		8		(27)
Other Comprehensive Income, Net of Tax				104		110		341		306
Comprehensive Income			$	83,980	$	66,433	$	200,901	$	219,494



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 Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013

Operating Activities:
	Net Income		$	200,560	$	219,188
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		139,598		132,356
		Deferred Income Taxes		(14,400)		89,084
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		8,050		16,182
		Regulatory Overrecoveries, Net		62,929		24,061
		Amortization of Regulatory Assets, Net		62,644		11,223
		Proceeds from DOE Damages Claim		68,610		-
		Other		(11,290)		(8,759)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(87,922)		(44,523)
		Taxes Receivable/Accrued, Net		39,805		841
		Accounts Payable		16,984		(101,949)
		Other Current Assets and Liabilities, Net		(2,575)		(29,106)
Net Cash Flows Provided by Operating Activities				482,993		308,598

Investing Activities:
	Investments in Property, Plant and Equipment			(371,660)		(294,638)
	Other Investing Activities			(4,539)		2,013
Net Cash Flows Used in Investing Activities				(376,199)		(292,625)

Financing Activities:
	Cash Dividends on Common Stock			(128,400)		(114,000)
	Cash Dividends on Preferred Stock			(4,169)		(4,169)
	Issuance of Long-Term Debt			250,000		400,000
	Retirements of Long-Term Debt			(150,000)		(125,000)
	Decrease in Notes Payable to NU Parent			(181,900)		(62,200)
	Capital Contribution from NU Parent			120,000		-
	Decrease in Short-Term Debt			-		(89,000)
	Other Financing Activities			(3,268)		(6,352)
Net Cash Flows Used in Financing Activities				(97,737)		(721)
Net Increase in Cash				9,057		15,252
Cash - Beginning of Period				7,237		1
Cash - End of Period			$	16,294	$	15,253

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


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


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

ASSETS

Current Assets:
	Cash and Cash Equivalents	$	11,040	$	8,021
	Receivables, Net		275,902		209,711
	Accounts Receivable from Affiliated Companies		47,215		27,264
	Unbilled Revenues		39,372		41,368
	Materials and Supplies		65,073		44,236
	Regulatory Assets		128,205		204,144
	Prepayments and Other Current Assets		11,267		36,710
Total Current Assets			578,074		571,454

Property, Plant and Equipment, Net			5,211,681		5,043,887

Deferred Debits and Other Assets:
	Regulatory Assets		998,030		1,235,156
	Other Long-Term Assets		62,644		60,624
Total Deferred Debits and Other Assets			1,060,674		1,295,780



Total Assets		$	6,850,429	$	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)


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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable		$	159,500	$	103,500
	Long-Term Debt - Current Portion			4,700		301,650
	Accounts Payable			128,056		202,100
	Accounts Payable to Affiliated Companies			62,625		75,707
	Obligations to Third Party Suppliers			37,298		5,459
	Power Contract Obligations			35,783		30,842
	Renewable Portfolio Standards Compliance Obligations			34,905		39,686
	Accrued Taxes			42,338		7,946
	Accumulated Deferred Income Taxes			9,622		50,128
	Regulatory Liabilities			97,215		53,958
	Other Current Liabilities			62,436		39,936
Total Current Liabilities				674,478		910,912

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,425,306		1,466,835
	Regulatory Liabilities			266,524		253,108
	Accrued Pension, SERP and PBOP			142,249		118,010
	Payable to Affiliated Companies			-		64,172
	Other Long-Term Liabilities			112,853		142,214
Total Deferred Credits and Other Liabilities				1,946,932		2,044,339

Capitalization:
	Long-Term Debt			1,792,707		1,499,417

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

	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		993,163		992,625
		Retained Earnings		1,400,149		1,420,828
	Common Stockholder's Equity			2,393,312		2,413,453
Total Capitalization				4,229,019		3,955,870

Total Liabilities and Capitalization			$	6,850,429	$	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 September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013			2014		2013

Operating Revenues			$	727,909	$	753,879	$	1,955,609	$	1,916,557

Operating Expenses:
	Purchased Power and Transmission			317,784		255,244		879,773		659,140
	Operations and Maintenance			79,705		97,069		244,610		277,261
	Depreciation			47,455		45,441		140,996		136,323
	Amortization of Regulatory Assets/(Liabilities), Net			(15,063)		72,740		(916)		173,289
	Amortization of Rate Reduction Bonds			-		-		-		15,054
	Energy Efficiency Programs			56,915		58,798		145,499		161,180
	Taxes Other Than Income Taxes			34,513		32,610		99,121		95,275
		Total Operating Expenses		521,309		561,902		1,509,083		1,517,522
Operating Income				206,600		191,977		446,526		399,035

Interest Expense:
	Interest on Long-Term Debt			17,996		19,860		58,485		59,261
	Other Interest			(658)		(1,324)		606		(7,612)
		Interest Expense		17,338		18,536		59,091		51,649
Other Income, Net				3,287		2,126		3,011		3,275
Income Before Income Tax Expense				192,549		175,567		390,446		350,661
Income Tax Expense				76,975		68,558		156,655		137,499
Net Income			$	115,574	$	107,009	$	233,791	$	213,162



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 Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013

Operating Activities:
	Net Income		$	233,791	$	213,162
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		140,996		136,323
		Deferred Income Taxes		(39,399)		26,358
		Pension and PBOP Expense, Net of Contributions		(11,046)		(55,195)
		Regulatory Over/(Under) Recoveries, Net		155,357		(11,299)
		Amortization of Regulatory Assets, Net		(916)		173,289
		Amortization of Rate Reduction Bonds		-		15,054
		Proceeds from DOE Damages Claim		30,193		-
		Bad Debt Expense		15,250		19,012
		Other		(56,851)		(48,291)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(47,770)		(80,575)
		Materials and Supplies		(20,837)		7,961
		Taxes Receivable/Accrued, Net		60,252		(6,345)
		Accounts Payable		(40,594)		6,856
		Accounts Receivable from/Payable to Affiliates, Net		66,758		(59,173)
		Other Current Assets and Liabilities, Net		32,340		(19,547)
Net Cash Flows Provided by Operating Activities				517,524		317,590

Investing Activities:
	Investments in Property, Plant and Equipment			(309,248)		(330,635)
	Decrease in Special Deposits			-		37,899
	Other Investing Activities			-		575
Net Cash Flows Used in Investing Activities				(309,248)		(292,161)

Financing Activities:
	Cash Dividends on Common Stock			(253,000)		(56,000)
	Cash Dividends on Preferred Stock			(1,470)		(1,633)
	Increase/(Decrease) in Notes Payable			56,000		(120,000)
	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)		(878)
Net Cash Flows Used in Financing Activities				(205,257)		(23,654)
Net Increase in Cash and Cash Equivalents				3,019		1,775
Cash and Cash Equivalents - Beginning of Period				8,021		13,695
Cash and Cash Equivalents - End of Period			$	11,040	$	15,470



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)


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

ASSETS

Current Assets:
	Cash	$	2,750	$	130
	Receivables, Net		77,602		76,331
	Accounts Receivable from Affiliated Companies		6,271		90
	Unbilled Revenues		33,088		38,344
	Fuel, Materials and Supplies		141,381		128,736
	Regulatory Assets		102,473		92,194
	Prepayments and Other Current Assets		22,270		24,100
Total Current Assets			385,835		359,925

Property, Plant and Equipment, Net			2,560,635		2,467,556

Deferred Debits and Other Assets:
	Regulatory Assets		178,204		219,346
	Other Long-Term Assets		54,748		39,891
Total Deferred Debits and Other Assets			232,952		259,237



Total Assets		$	3,179,422	$	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)


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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to NU Parent		$	153,300	$	86,500
	Long-Term Debt - Current Portion			-		50,000
	Accounts Payable			58,801		82,920
	Accounts Payable to Affiliated Companies			22,932		22,040
	Regulatory Liabilities			29,165		20,643
	Accumulated Deferred Income Taxes			29,936		28,596
	Other Current Liabilities			38,725		51,729
Total Current Liabilities				332,859		342,428

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			566,298		500,166
	Regulatory Liabilities			50,614		51,723
	Accrued SERP and PBOP			14,320		15,272
	Other Long-Term Liabilities			46,874		46,247
Total Deferred Credits and Other Liabilities				678,106		613,408

Capitalization:
	Long-Term Debt			999,230		999,006

	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		702,923		701,911
		Retained Earnings		473,969		438,515
		Accumulated Other Comprehensive Loss		(7,665)		(8,550)
	Common Stockholder's Equity			1,169,227		1,131,876
Total Capitalization				2,168,457		2,130,882

Total Liabilities and Capitalization			$	3,179,422	$	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 September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013		2014			2013

Operating Revenues			$	223,664	$	218,608	$	735,123	$	708,550

Operating Expenses:
	Purchased Power, Fuel and Transmission			64,397		46,668		247,992		197,765
	Operations and Maintenance			65,563		69,477		198,025		191,606
	Depreciation			24,568		22,919		73,247		68,433
	Amortization of Regulatory Assets/(Liabilities), Net			(9,734)		225		(17,565)		(1,745)
	Amortization of Rate Reduction Bonds			-		-		-		19,748
	Energy Efficiency Programs			3,766		3,990		10,897		11,036
	Taxes Other Than Income Taxes			18,702		18,706		53,051		52,640
		Total Operating Expenses		167,262		161,985		565,647		539,483
Operating Income				56,402		56,623		169,476		169,067

Interest Expense:
	Interest on Long-Term Debt			10,896		10,345		33,812		32,951
	Other Interest			128		521		183		1,230
		Interest Expense		11,024		10,866		33,995		34,181
Other Income, Net				461		792		1,673		2,454
Income Before Income Tax Expense				45,839		46,549		137,154		137,340
Income Tax Expense				17,603		18,196		52,199		52,797
Net Income			$	28,236	$	28,353	$	84,955	$	84,543



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





CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income			$	28,236	$	28,353	$	84,955	$	84,543
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			290		290		871		872
	Changes in Unrealized Gains/(Losses) on Other Securities			(13)		(2)		14		(47)
	Changes in Funded Status of Pension, SERP and PBOP Benefit Plans			-		-		-		(3)
Other Comprehensive Income, Net of Tax				277		288		885		822
Comprehensive Income			$	28,513	$	28,641	$	85,840	$	85,365



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 Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013

Operating Activities:
	Net Income		$	84,955	$	84,543
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		73,247		68,433
		Deferred Income Taxes		67,827		57,066
		Pension, SERP and PBOP Expense		4,541		20,427
		Pension and PBOP Contributions		(1,637)		(112,964)
		Regulatory Over/(Under) Recoveries, Net		16,813		(1,346)
		Amortization of Regulatory Liabilities, Net		(17,565)		(1,745)
		Amortization of Rate Reduction Bonds		-		19,748
		Proceeds from DOE Damages Claim		14,453		-
		Other		7,930		7,165
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(7,467)		8,047
		Fuel, Materials and Supplies		(17,350)		(30,456)
		Taxes Receivable/Accrued, Net		(24,108)		5,103
		Accounts Payable		(9,297)		29,148
		Other Current Assets and Liabilities, Net		13,470		7,220
Net Cash Flows Provided by Operating Activities				205,812		160,389

Investing Activities:
	Investments in Property, Plant and Equipment			(170,127)		(155,676)
	(Increase)/Decrease in Special Deposits			(45)		22,039
	Other Investing Activities			(103)		(53)
Net Cash Flows Used in Investing Activities				(170,275)		(133,690)

Financing Activities:
	Cash Dividends on Common Stock			(49,500)		(51,000)
	Increase in Notes Payable to NU Parent			66,800		165,200
	Retirements of Long-Term Debt			(50,000)		(108,950)
	Retirements of Rate Reduction Bonds			-		(29,294)
	Other Financing Activities			(217)		456
Net Cash Flows Used in Financing Activities				(32,917)		(23,588)
Net Increase in Cash				2,620		3,111
Cash - Beginning of Period				130		2,493
Cash - End of Period			$	2,750	$	5,604



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


WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)


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

ASSETS

Current Assets:
	Cash	$	1,737	$	-
	Receivables, Net		50,835		49,018
	Accounts Receivable from Affiliated Companies		14,522		47,607
	Unbilled Revenues		12,664		16,562
	Taxes Receivable		11,504		432
	Regulatory Assets		38,907		43,024
	Marketable Securities		22,107		26,628
	Prepayments and Other Current Assets		6,688		10,479
Total Current Assets			158,964		193,750

Property, Plant and Equipment, Net			1,432,368		1,381,060

Deferred Debits and Other Assets:
	Regulatory Assets		109,690		146,088
	Marketable Securities		35,963		31,243
	Other Long-Term Assets		50,902		40,679
Total Deferred Debits and Other Assets			196,555		218,010



Total Assets		$	1,787,887	$	1,792,820



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


WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)


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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to NU Parent		$	13,200	$	-
	Long-Term Debt - Current Portion			50,000		-
	Accounts Payable			36,558		62,961
	Accounts Payable to Affiliated Companies			13,312		9,230
	Accrued Interest			2,839		7,525
	Regulatory Liabilities			43,462		19,858
	Accumulated Deferred Income Taxes			1,920		13,098
	Counterparty Deposits			626		7,688
	Other Current Liabilities			11,758		20,629
Total Current Liabilities				173,675		140,989

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			413,701		396,933
	Regulatory Liabilities			10,289		13,873
	Accrued SERP and PBOP			2,623		3,911
	Other Long-Term Liabilities			38,372		28,619
Total Deferred Credits and Other Liabilities				464,985		443,336

Capitalization:
	Long-Term Debt			578,686		629,389

	Common Stockholder's Equity:
		Common Stock		10,866		10,866
		Capital Surplus, Paid In		391,136		390,743
		Retained Earnings		171,800		181,014
		Accumulated Other Comprehensive Loss		(3,261)		(3,517)
	Common Stockholder's Equity			570,541		579,106
Total Capitalization				1,149,227		1,208,495

Total Liabilities and Capitalization			$	1,787,887	$	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 September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013		2014		2013

Operating Revenues			$	118,145	$	121,795	$	363,843	$	361,763

Operating Expenses:
	Purchased Power and Transmission			43,926		38,797		130,977		111,095
	Operations and Maintenance			20,820		26,148		67,085		70,213
	Depreciation			10,506		9,426		31,144		27,707
	Amortization of Regulatory Liabilities, Net			(8,519)		(1,412)		(7,778)		(598)
	Amortization of Rate Reduction Bonds			-		-		-		7,780
	Energy Efficiency Programs			10,983		12,222		33,096		28,462
	Taxes Other Than Income Taxes			9,200		7,696		25,679		20,188
		Total Operating Expenses		86,916		92,877		280,203		264,847
Operating Income				31,229		28,918		83,640		96,916

Interest Expense:
	Interest on Long-Term Debt			6,029		5,814		18,195		17,846
	Other Interest			547		417		734		954
		Interest Expense		6,576		6,231		18,929		18,800
Other Income, Net				502		926		1,670		2,349
Income Before Income Tax Expense				25,155		23,613		66,381		80,465
Income Tax Expense				10,490		8,588		26,596		30,424
Net Income			$	14,665	$	15,025	$	39,785	$	50,041



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


CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income		$	14,665	$	15,025	$	39,785	$	50,041
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments		85		85		254		254
	Changes in Unrealized Gains/(Losses) on Other Securities		(2)		-		2		(8)
Other Comprehensive Income, Net of Tax			83		85		256		246
Comprehensive Income		$	14,748	$	15,110	$	40,041	$	50,287



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 Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013

Operating Activities:
	Net Income		$	39,785	$	50,041
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		31,144		27,707
		Deferred Income Taxes		13,479		79,401
		Regulatory Overrecoveries, Net		33,630		11,685
		Amortization of Regulatory Liabilities, Net		(7,778)		(598)
		Amortization of Rate Reduction Bonds		-		7,780
		Proceeds from DOE Damages Claim		18,883		-
		Other		615		(544)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		36,075		(32,231)
		Taxes Receivable/Accrued, Net		(15,831)		16,412
		Accounts Payable		(12,847)		20,260
		Other Current Assets and Liabilities, Net		(16,551)		(9,857)
Net Cash Flows Provided by Operating Activities				120,604		170,056

Investing Activities:
	Investments in Property, Plant and Equipment			(82,546)		(127,352)
	Proceeds from Sales of Marketable Securities			58,788		53,552
	Purchases of Marketable Securities			(59,280)		(54,042)
	Other Investing Activities			-		7,401
Net Cash Flows Used in Investing Activities				(83,038)		(120,441)

Financing Activities:
	Cash Dividends on Common Stock			(49,000)		(30,000)
	Retirement of Long-Term Debt			-		(55,000)
	Increase in Notes Payable to NU Parent			13,200		47,900
	Retirement of Rate Reduction Bonds			-		(9,352)
	Other Financing Activities			(29)		(7)
Net Cash Flows Used in Financing Activities				(35,829)		(46,459)
Net Increase in Cash				1,737		3,156
Cash - Beginning of Period				-		1
Cash - End of Period			$	1,737	$	3,157


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 and second quarter 2014 combined Quarterly Reports 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 September 30, 2014 and December 31, 2013, the results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013. The results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013 are not necessarily indicative of the results expected for a full year.

NU consolidates CYAPC and YAEC because 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 September 30, 2014		As of December 31, 2013
NU	$	181.4	$	171.3
CL&P		85.8		82.0
NSTAR Electric		42.3		41.7
PSNH		7.9		7.4
WMECO		11.1		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, and is also used to estimate the fair value of preferred stock and long-term debt.

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 10, "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.

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 Nine Months Ended
(Millions of Dollars)	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
NU	$	35.0	$	37.5	$	114.6	$	108.9
CL&P		32.5		35.5		99.0		97.3

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 September 30, 2014		As of September 30, 2013
NU	$	128.9	$	122.9
CL&P		52.2		36.6
NSTAR Electric		18.1		31.9
PSNH		21.0		16.9
WMECO		10.0		13.8

In the first nine months of 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," NU received total proceeds of $132.1 million, which were net of $80.6 million in proceeds CYAPC and YAEC returned to non-affiliated member companies.

Severance Benefits

NU recorded severance benefit expenses of $0.7 million and $6.5 million associated with the partial outsourcing of information technology functions and ongoing post-merger integration for the three and nine months ended September 30, 2014, respectively, and $9.2 million for the three and nine months ended September 30, 2013. As of September 30, 2014 and December 31, 2013, the severance accrual totaled $6.4 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 September 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Benefit Costs	$	1,113.2	$	1,240.2
Derivative Liabilities		427.5		638.0
Income Taxes, Net		623.2		626.2
Storm Restoration Costs		493.5		589.6
Goodwill-related		510.5		525.9
Regulatory Tracker Mechanisms		235.7		323.4
Contractual Obligations - Yankee Companies		124.6		154.2
Buy Out Agreements for Power Contracts		49.8		70.2
Other Regulatory Assets		109.1		126.8
Total Regulatory Assets		3,687.1		4,294.5
Less: Current Portion		446.0		535.8
Total Long-Term Regulatory Assets	$	3,241.1	$	3,758.7


	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Benefit Costs	$	242.2	$	318.1	$	78.1	$	44.3	$	297.7	$	496.7	$	100.6	$	57.3
Derivative Liabilities		421.1		4.3		-		-		630.4		7.7		-		-
Income Taxes, Net		427.4		83.3		38.3		35.3		415.5		84.0		40.3		43.7
Storm Restoration Costs		326.0		106.2		29.3		32.0		397.8		109.3		43.7		38.8
Goodwill-related		-		438.3		-		-		-		451.5		-		-
Regulatory Tracker Mechanisms		5.2		76.4		94.7		23.5		8.0		169.5		83.3		32.6
Buy Out Agreements for Power Contracts		-		45.4		4.4		-		-		64.7		5.5		-
Other Regulatory Assets		63.6		54.2		35.9		13.5		64.6		55.9		38.1		16.7
Total Regulatory Assets		1,485.5		1,126.2		280.7		148.6		1,814.0		1,439.3		311.5		189.1
Less: Current Portion		116.5		128.2		102.5		38.9		150.9		204.1		92.2		43.0
Total Long-Term Regulatory Assets	$	1,369.0	$	998.0	$	178.2	$	109.7	$	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 (with carrying charges) associated with five major storms that occurred in 2011 and 2012. CL&P will recover these costs in its distribution rates over a six-year period beginning December 1, 2014. Effective June 1, 2014, CL&P received $65.4 million of DOE Phase II Damages proceeds. On June 17, 2014,

the PURA ordered CL&P to refund these proceeds to customers by offsetting the deferred storm restoration costs regulatory asset. For further information on the DOE Phase II Damages proceeds received from the Yankee Companies, see Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.

Regulatory Costs in Other Long-Term Assets: The Regulated companies had $64.7 million ($3.2 million for CL&P, $36 million for NSTAR Electric, and $11.2 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 September 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 September 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Cost of Removal	$	439.1	$	435.1
Regulatory Tracker Mechanisms		339.9		151.2
AFUDC - Transmission		67.2		68.1
Other Regulatory Liabilities		62.7		52.9
Total Regulatory Liabilities		908.9		707.3
Less: Current Portion		399.0		204.3
Total Long-Term Regulatory Liabilities	$	509.9	$	503.0


	As of September 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	$	22.5	$	260.7	$	49.2	$	-	$	29.1	$	250.0	$	49.7	$	-
Regulatory Tracker Mechanisms		196.4		67.3		25.9		43.9		95.6		21.9		21.6		21.1
AFUDC - Transmission		53.9		4.1		-		9.2		54.7		4.1		-		9.3
Other Regulatory Liabilities		10.6		31.6		4.7		0.7		8.4		31.1		1.0		3.4
Total Regulatory Liabilities		283.4		363.7		79.8		53.8		187.8		307.1		72.3		33.8
Less: Current Portion		195.7		97.2		29.2		43.5		94.0		54.0		20.6		19.9
Total Long-Term Regulatory Liabilities	$	87.7	$	266.5	$	50.6	$	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 9E, "Commitments and Contingencies – FERC Base ROE Complaints," in the second quarter of 2014 the Company had recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings. As of September 30, 2014, the cumulative pre-tax reserves (excluding interest) totaled $76.1 million at NU, $42.9 million at CL&P, $15.6 million at NSTAR Electric, $5.9 million at PSNH and $11.7 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 (excluding interest) of $23.7 million at NU, $12.8 million at CL&P, $5.7 million at NSTAR Electric, $2.3 million at PSNH and $2.9 million at WMECO. These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of Operating Revenues.

Effective June 1, 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 9C, "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. 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. Refunds to customers for these DOE proceeds began in the third quarter of 2014.

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

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


		As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)		NU		NU
Distribution - Electric		$	12,306.6	$	11,950.2
Distribution - Natural Gas			2,494.5		2,425.9
Transmission			6,564.2		6,412.5
Generation			1,168.6		1,152.3
Electric and Natural Gas Utility			22,533.9		21,940.9
Other⁽¹⁾			541.7		508.7
Property, Plant and Equipment, Gross			23,075.6		22,449.6
Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(5,687.0)		(5,387.0)
	Other		(216.3)		(196.2)
Total Accumulated Depreciation			(5,903.3)		(5,583.2)
Property, Plant and Equipment, Net			17,172.3		16,866.4
Construction Work in Progress			1,082.3		709.8
Total Property, Plant and Equipment, Net		$	18,254.6	$	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 September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Distribution	$	5,104.8	$	4,812.4	$	1,654.5	$	774.8	$	4,930.7	$	4,694.7	$	1,608.2	$	756.6
Transmission		3,125.2		1,824.6		715.8		851.8		3,071.9		1,772.3		695.7		826.4
Generation		-		-		1,134.7		33.9		-		-		1,131.2		21.1
Property, Plant and Equipment, Gross		8,230.0		6,637.0		3,505.0		1,660.5		8,002.6		6,467.0		3,435.1		1,604.1
Less: Accumulated Depreciation		(1,908.2)		(1,726.7)		(1,069.4)		(291.8)		(1,804.1)		(1,631.3)		(1,021.8)		(271.5)
Property, Plant and Equipment, Net		6,321.8		4,910.3		2,435.6		1,368.7		6,198.5		4,835.7		2,413.3		1,332.6
Construction Work in Progress		379.0		301.4		125.0		63.7		252.8		208.2		54.3		48.5
Total Property, Plant and Equipment, Net	$	6,700.8	$	5,211.7	$	2,560.6	$	1,432.4	$	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, which are subject to price volatility, for their customers. 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. 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 September 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	$	-	$	0.4
Level 3:
	NU⁽¹⁾		17.4		(6.8)		10.6
	CL&P⁽¹⁾		16.4		(6.8)		9.6
	NSTAR Electric		1.0		-		1.0

Long-Term Derivative Assets:
Level 3:
	NU⁽¹⁾	$	96.0	$	(20.9)	$	75.1
	CL&P⁽¹⁾		95.1		(20.9)		74.2
	NSTAR Electric		0.9		-		0.9

Current Derivative Liabilities:
Level 2:
	NU⁽¹⁾	$	(2.4)	$	0.4	$	(2.0)
Level 3:
	NU		(88.3)		-		(88.3)
	CL&P		(86.8)		-		(86.8)
	NSTAR Electric		(1.5)		-		(1.5)

Long-Term Derivative Liabilities:
Level 3:
	NU	$	(420.9)	$	-	$	(420.9)
	CL&P		(418.1)		-		(418.1)
	NSTAR Electric		(2.8)		-		(2.8)


		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 At Fair Value with Offsetting Regulatory Amounts

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 September 30, 2014 and December 31, 2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 9.7 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 September 30,				For the Nine Months Ended September 30,
(Millions of Dollars)		2014		2013		2014		2013
NU
Balance Sheets:
	Regulatory Assets and Liabilities	$	(15.7)	$	0.3	$	149.9	$	48.8
Statements of Income:
	Purchased Power, Fuel and Transmission		-		0.2		-		0.9

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 September 30, 2014							As of December 31, 2013
		Range					Period Covered		Range					Period Covered
Energy Prices:
NU	$	66	-	68	per MWh		2018 - 2020	$	49	-	77	per MWh		2018 - 2029
CL&P	$	66	-	68	per MWh		2018 - 2020	$	56	-	58	per MWh		2018 - 2029

Capacity Prices:
NU	$	7.03	-	12.98		per kW-Month	2016 - 2026	$	5.07	-	11.82		per kW-Month	2017 - 2029
CL&P	$	7.03	-	12.98		per kW-Month	2018 - 2026	$	5.07	-	10.42		per kW-Month	2017 - 2026
NSTAR Electric	$	11.00	-	11.10		per kW-Month	2016 - 2019	$	5.07	-	7.38		per kW-Month	2017 - 2019

Forward Reserve:
NU, CL&P	$	5.80	-	9.50		per kW-Month	2014 - 2024	$	3.30	-	3.30		per kW-Month	2014 - 2024

REC Prices:
NU	$	41	-	70	per REC		2014 - 2018	$	36	-	87	per REC		2014 - 2029
NSTAR Electric	$	41	-	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 September 30,				For the Nine Months Ended September 30,
		2014		2013		2014		2013
(Millions of Dollars)		NU		NU		NU		NU
Derivatives, Net:
Fair Value as of Beginning of Period		$	(430.9)	$	(788.1)	$	(635.2)	$	(878.6)
Net Realized/Unrealized Gains Included in:
	Net Income		-		1.2		-		8.3
	Regulatory Assets and Liabilities		(13.6)		0.8		147.6		49.6
Settlements			21.0		21.3		64.1		55.9
Fair Value as of End of Period		$	(423.5)	$	(764.8)	$	(423.5)	$	(764.8)


	For the Three Months Ended September 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(424.6)	$	(6.3)	$	(775.8)	$	(13.1)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		(15.0)		1.4		(1.2)		0.5
Settlements		18.5		2.5		21.7		1.0
Fair Value as of End of Period	$	(421.1)	$	(2.4)	$	(755.3)	$	(11.6)


	For the Nine Months Ended September 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		149.4		0.9		45.1		0.6
Settlements		60.1		4.0		65.8		2.7
Fair Value as of End of Period	$	(421.1)	$	(2.4)	$	(755.3)	$	(11.6)

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 September 30, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $58.2 million and $24.4 million, respectively. As of December 31, 2013, the mutual funds were classified as Level 1 and totaled $57.2 million. For the three months ended September 30, 2014 and 2013, net losses of $1.9 million and net gains of $3 million, respectively, were recorded in Other Income, Net. For the nine months ended September 30, 2014 and 2013, net gains of $1.9 million and $7.3 million, respectively, were recorded in Other Income, Net. 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 September 30, 2014
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities⁽¹⁾	$	310.6	$	7.8	$	(0.2)	$	318.2
	Equity Securities⁽¹⁾		160.9		71.1		-		232.0

WMECO
	Debt Securities⁽²⁾		58.1		0.1		(0.1)		58.1


		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 $447.7 million and $424 million as of September 30, 2014 and December 31, 2013, respectively, which are legally restricted and can only be used for the costs of 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 September 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⁾	$	47.6	$	47.6	$	21.9	$	22.1
One to five years		91.0		91.4		30.7		30.5
Six to ten years		65.6		67.5		1.4		1.4
Greater than ten years		106.4		111.7		4.1		4.1
Total Debt Securities	$	310.6	$	318.2	$	58.1	$	58.1

⁽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)		September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Level 1:
	Mutual Funds and Equities	$	314.6	$	281.3	$	-	$	-
	Money Market Funds		27.1		32.9		4.4		10.9
Total Level 1		$	341.7	$	314.2	$	4.4	$	10.9
Level 2:
	U.S. Government Issued Debt Securities (Agency and Treasury)	$	56.5	$	61.4	$	-	$	6.8
	Corporate Debt Securities		61.2		53.6		14.1		15.1
	Asset-Backed Debt Securities		37.9		30.4		14.3		9.0
	Municipal Bonds		112.5		105.5		13.9		11.2
	Other Fixed Income Securities		23.0		15.8		11.4		4.9
Total Level 2		$	291.1	$	266.7	$	53.7	$	47.0
Total Marketable Securities		$	632.8	$	580.9	$	58.1	$	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 extended the expiration date of their joint $1.45 billion revolving credit facility for one 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 September 30, 2014 and December 31, 2013, NU had $964.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $485.5 million and $435.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of September 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 September 30, 2014, there were intercompany loans from NU of $105.4 million to CL&P, $153.3 million to PSNH and $13.2 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 extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of September 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.

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. As the debt issuance refinanced short-term debt, the short-term debt was 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 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 borrowings.

On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds.

On October 14, 2014, PSNH issued $75 million of first mortgage bonds at a yield of 3.144 percent that will mature on November 1, 2023. The first mortgage bonds are part of the same series of PSNH’s existing 3.50 percent Series S First Mortgage Bonds that were initially issued in November 2013. As a result, the aggregate principal amount of PSNH’s outstanding Series S First Mortgage Bonds totals $325 million. The proceeds, net of issuance costs, were used to repay short-term borrowings. As the debt issuance refinanced short-term debt, the short-term debt was classified as Long-Term Debt on NU's balance sheet as of September 30, 2014.

On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

The components of net periodic benefit expense for the Pension, SERP and PBOP Plans are shown 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 Nine Months Ended
	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	19.1	$	25.6	$	60.7	$	76.7
Interest Cost		56.4		51.7		169.5		155.0
Expected Return on Plan Assets		(77.7)		(69.5)		(233.1)		(208.5)
Actuarial Loss		31.7		52.4		96.5		158.1
Prior Service Cost		1.1		1.1		3.3		3.0
Total Net Periodic Benefit Expense	$	30.6	$	61.3	$	96.9	$	184.3
Capitalized Pension Expense	$	8.3	$	18.3	$	26.7	$	54.9

	PBOP				PBOP
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	3.1	$	4.2	$	9.3	$	12.6
Interest Cost		12.4		11.8		37.1		35.4
Expected Return on Plan Assets		(15.8)		(13.9)		(47.4)		(41.6)
Actuarial Loss		3.0		6.5		9.1		19.5
Prior Service Credit		(0.7)		(0.5)		(2.1)		(1.5)
Total Net Periodic Benefit Expense	$	2.0	$	8.1	$	6.0	$	24.4
Capitalized PBOP Expense	$	1.1	$	2.6	$	1.9	$	7.6


	Pension and SERP
	For the Three Months Ended September 30, 2014								For the Three Months Ended September 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	$	8.3		3.3	$	1.2
Interest Cost		12.5		10.3		5.7		2.5		12.1		14.5		5.8		2.5
Expected Return on Plan Assets		(18.7)		(15.7)		(9.3)		(4.4)		(18.4)		(21.1)		(9.2)		(4.3)
Actuarial Loss		8.2		5.9		2.8		1.7		13.9		14.4		5.4		2.9
Prior Service Cost		0.4		-		0.1		0.1		0.4		-		0.1		0.1
Total Net Periodic Benefit Expense	$	7.4	$	3.5	$	1.6	$	0.7	$	14.3	$	16.1	$	5.4	$	2.4
Intercompany Allocations	$	6.5	$	2.9	$	1.8	$	1.2	$	11.4	$	(2.1)	$	2.6	$	2.0
Capitalized Pension Expense	$	4.3	$	2.6	$	0.7	$	0.6	$	7.0	$	9.8	$	1.7	$	1.3

	Pension and SERP
	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric⁽¹⁾		PSNH		WMECO
Service Cost	$	15.2	$	10.6	$	7.4	$	2.7	$	18.7	$	24.8	$	9.8	$	3.5
Interest Cost		38.1		31.0		18.0		7.8		36.3		43.5		17.8		7.5
Expected Return on Plan Assets		(56.7)		(47.3)		(28.8)		(13.5)		(55.4)		(63.3)		(26.2)		(13.0)
Actuarial Loss		25.5		17.6		8.9		5.2		42.0		43.6		16.2		8.9
Prior Service Cost/(Credit)		1.4		-		0.5		0.3		1.4		(0.2)		0.4		0.3
Total Net Periodic Benefit Expense	$	23.5	$	11.9	$	6.0	$	2.5	$	43.0	$	48.4	$	18.0	$	7.2
Intercompany Allocations	$	20.8	$	6.7	$	6.0	$	3.9	$	33.6	$	(6.2)	$	7.8	$	6.0
Capitalized Pension Expense	$	13.6	$	5.5	$	2.4	$	2.0	$	21.0	$	21.6	$	5.6	$	3.9


	PBOP
	For the Three Months Ended September 30, 2014								For the Three Months Ended September 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	0.6	$	0.8	$	0.3	$	0.1	$	0.9	$	0.6	$	0.2
Interest Cost		2.0		4.9		1.1		0.4		2.0		1.0		0.4
Expected Return on Plan Assets		(2.6)		(6.5)		(1.4)		(0.6)		(2.5)		(1.3)		(0.6)
Actuarial Loss/(Gain)		1.0		(0.1)		0.6		0.1		1.8		0.9		0.3
Prior Service Credit		-		(0.5)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	1.0	$	(1.4)	$	0.6	$	0.0	$	2.2	$	1.2	$	0.3
Intercompany Allocations	$	0.9	$	0.3	$	0.2	$	0.2	$	1.7	$	0.4	$	0.3
Capitalized PBOP Expense/(Income)	$	0.5	$	(0.5)	$	0.2	$	-	$	1.3	$	0.4	$	0.3


	PBOP
	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	1.7	$	2.3	$	1.0	$	0.3	$	2.6	$	1.7	$	0.5
Interest Cost		6.0		14.6		3.2		1.3		5.9		3.1		1.3
Expected Return on Plan Assets		(7.9)		(19.5)		(4.1)		(1.7)		(7.6)		(3.9)		(1.7)
Actuarial Loss/(Gain)		3.2		(0.4)		1.7		0.3		5.6		2.7		0.8
Prior Service Credit		-		(1.4)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	3.0	$	(4.4)	$	1.8	$	0.2	$	6.5	$	3.6	$	0.9
Intercompany Allocations	$	3.1	$	0.4	$	0.8	$	0.6	$	5.3	$	1.2	$	1.0
Capitalized PBOP Expense/(Income)	$	1.5	$	(1.5)	$	0.6	$	0.1	$	3.7	$	1.1	$	0.7

⁽¹⁾

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

For the three and nine months ended September 30, 2013, the net periodic PBOP expense allocated to NSTAR Electric was $1.2 million and $3.5 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. This change had no impact on the income statement or net assets of NSTAR Electric or NU.

As of September 30, 2014, the liabilities associated with the Pension, SERP and PBOP plans for NSTAR Electric were $83.4 million for the Pension Plan, $3.6 million for the SERP Plans ($0.4 million of which is included in other current liabilities) and $55.6 million for the PBOP Plan. As of December 31, 2013, the liability associated with the NSTAR Pension Plan for NSTAR Electric was $118 million.

INCOME TAXES

In the third quarter of 2014, the Company recorded a reduction to its state credit carryforwards of $11 million (CL&P $10.1 million), net of tax, as a result of an update to reflect the amounts expired. Further, the Company decreased its valuation allowance reserve for state credits by $22.3 million (all at CL&P), net of tax, to reflect the expiration of state credits in its recently filed return and the latest available data. These updates resulted in a net reduction in income tax expense of $11.3 million (CL&P $12.2 million).

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 September 30, 2014				As of December 31, 2013
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		65	$	34.7		68	$	35.4
CL&P		16		4.0		18		3.4
NSTAR Electric		13		1.1		12		1.2
PSNH		13		5.3		15		5.4
WMECO		4		0.5		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 September 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 CL&P, NSTAR Electric and WMECO for the purchase of energy and capacity from renewable energy facilities.


	October - December
(Millions of Dollars)	2014		2015		2016		2017		2018		Thereafter		Total
CL&P	$	20.0	$	60.7	$	66.1	$	67.0	$	67.7	$	717.0	$	998.5
NSTAR Electric		21.8		86.3		100.0		96.1		59.6		377.6		741.4
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 September 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. Refunds to customers for these DOE proceeds began in the third quarter of 2014. 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.

DOE Phase I Damages - Proceeds Received – On September 17, 2014, in accordance with the MYAPC refund plan, MYAPC returned a portion of the DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, in the amount of $3.2 million, $1.1 million, $1.4 million and $0.8 million, respectively. These amounts reduced receivables at CL&P, NSTAR Electric, PSNH and WMECO.

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 September 30, 2014:


		Maximum Exposure
Subsidiary	Description	(in millions)		Expiration Dates
Various	Surety Bonds	$	64.3	2014 - 2016 ⁽¹⁾

Various	New England Hydro Companies' Long-Term Debt	$	2.0	Unspecified

NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	15.3	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

First Complaint: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act (the "first complaint") 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 prospectively from the date of a final FERC order (the "FERC order date"), and for the 15-month period October 1, 2011 to December 31, 2012 (the "first complaint refund period"), 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 on the first complaint finding that the base ROE in effect during the first complaint refund period was not reasonable and recommended separate base ROEs for the first complaint refund period of 10.6 percent and for the period beginning when FERC issues its final decision (the "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 first complaint refund period. See Cumulative Reserves below for further information on the reserves recorded in the third quarter of 2013.

On June 19, 2014, FERC issued an order on the first complaint, partially affirming and partially reversing the FERC ALJ's initial decision. FERC set a single tentative base ROE of 10.57 percent for the first complaint 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 halfway between the midpoint and the top of the zone of reasonableness. 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 (the "paper hearing"). Rehearing requests on this new methodology were filed in July, and briefs were filed in August and September by the parties on the appropriate long-term growth rate. In the second quarter of 2014, the Company recorded additional reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s June 19^th order. See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.

On October 16, 2014, the FERC issued an order in the paper hearing, which confirmed that the base ROE should be set at 10.57 percent and that a utility’s total or maximum ROE should not exceed the top of the new zone of reasonableness (11.74 percent). The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period, and set the new base ROE prospectively from the order date.

Second Complaint: On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties (the "second complaint"), which challenged the NETOs' base ROE prospectively from the FERC order date and sought refunds for the 15-month period January 1, 2013 to March 31, 2014 (the "second complaint refund period").

On June 19, 2014, FERC issued an order finding that the second complaint raised issues of material fact. On July 21, 2014, the NETOs filed a rehearing request in this proceeding. On October 24, 2014, the FERC assigned the case for trial before a FERC ALJ after settlement negotiations were unsuccessful. The FERC ALJ has set a trial date beginning June 8, 2015, and will issue an initial decision on or before October 26, 2015. In the second quarter of 2014, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s June 19^th order for the second complaint refund period. See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.

Third Complaint: On July 31, 2014, a third complaint was filed at FERC (the "third complaint") by most of the Complainants to the first and second complaints, claiming that the base ROE and incentive adders exceed the range of permissible ROEs, requesting FERC to reduce the NETO’s base ROE prospectively from the FERC order date, and seeking refunds for the 15-month period beginning August 1, 2014 (the "third complaint refund period"). FERC has taken no action on this complaint to date. At this time, the Company cannot determine the outcome of this complaint.

Cumulative Reserves: The following is a summary as of September 30, 2014 of the cumulative reserves (excluding interest) that the Company established in the third quarter of 2013 and the second quarter of 2014 to recognize the potential financial impacts of the first and second complaints. Management is currently evaluating the impact of the October 16^th order on the previously established reserves.


	NU
		Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total
1^st Complaint - Base ROE	$	23.7	$	1.2	$	24.9
2^nd Complaint - Base ROE		-		27.4		27.4
Incentive ROE (1^st and 2^nd Complaint)		-		23.8		23.8
Cumulative Reserve	$	23.7	$	52.4	$	76.1


	CL&P						NSTAR Electric
		Third Quarter		Second Quarter				Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total			2013		2014	Total
1^st Complaint - Base ROE	$	12.8	$	0.5	$	13.3	$	5.7	$	0.4	$	6.1
2^nd Complaint - Base ROE		-		13.5		13.5		-		7.5		7.5
Incentive ROE (1^st and 2^nd Complaint)		-		16.1		16.1		-		2.0		2.0
Cumulative Reserve	$	12.8	$	30.1	$	42.9	$	5.7	$	9.9	$	15.6


	PSNH						WMECO
		Third Quarter		Second Quarter				Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total			2013		2014	Total
1^st Complaint - Base ROE	$	2.3	$	0.1	$	2.4	$	2.9	$	0.2	$	3.1
2^nd Complaint - Base ROE		-		2.7		2.7		-		3.7		3.7
Incentive ROE (1^st and 2^nd Complaint)		-		0.8		0.8		-		4.9		4.9
Cumulative Reserve	$	2.3	$	3.6	$	5.9	$	2.9	$	8.8	$	11.7

The aggregate after-tax charge to second quarter 2014 earnings resulting from the June 19, 2014 FERC orders totaled $32.1 million at NU, $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO. In the third quarter of 2013, the aggregate after-tax charge to earnings totaled $14.3 million at NU, $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

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.

10.

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 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. 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 September 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	$	151.0	$	155.6	$	152.7
Long-Term Debt		8,412.6		8,876.3		8,310.2		8,443.1


	As of September 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	$	110.1	$	43.0	$	40.9	$	-	$	-	$	-	$	-
Long-Term Debt		2,841.8		3,189.5		1,797.4		1,959.4		999.2		1,046.4		628.7		667.4


	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 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.

See Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," for the fair value measurement policy and the fair value hierarchy.

11.

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

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


	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 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		-		0.2		1.2		1.4		-		(0.8)		-		(0.8)
Amounts Reclassified from AOCI		1.5		-		2.9		4.4		1.5		-		4.8		6.3
Net OCI		1.5		0.2		4.1		5.8		1.5		(0.8)		4.8		5.5
AOCI as of End of Period	$	(12.9)	$	0.6	$	(27.9)	$	(40.2)	$	(14.9)	$	0.5	$	(53.0)	$	(67.4)

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 Nine Months Ended
	September 30,				September 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)	$	(2.5)	$	(2.5)	Interest Expense
Tax Benefit		0.3		0.3		1.0		1.0	Income Tax Expense
Qualified Cash Flow Hedging Instruments, Net of Tax	$	(0.5)	$	(0.5)	$	(1.5)	$	(1.5)

Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses	$	(1.6)	$	(2.5)	$	(4.7)	$	(7.3)	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		(1.6)		(2.5)		(4.8)		(7.4)
Tax Benefit		0.6		0.9		1.9		2.6	Income Tax Expense
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax	$	(1.0)	$	(1.6)	$	(2.9)	$	(4.8)

Total Amounts Reclassified from AOCI, Net of Tax	$	(1.5)	$	(2.1)	$	(4.4)	$	(6.3)

⁽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.

12.

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		September 30, 2014 and	Issued as of
	Par Value		December 31, 2013	September 30, 2014	December 31, 2013
NU	$	5	380,000,000	333,353,446	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 September 30, 2014 and December 31, 2013, there were 16,730,815 and 17,796,672 NU common shares held as treasury shares, respectively. As of September 30, 2014 and December 31, 2013, NU common shares outstanding were 316,622,631 and 315,273,559, respectively.

13.

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
	September 30, 2014				September 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	$	9,753.8	$	155.6	$	9,406.6	$	155.6
Net Income		236.5		-		211.4		-
Dividends on Common Shares		(124.2)		-		(114.9)		-
Dividends on Preferred Stock		(1.9)		(1.9)		(1.9)		(1.9)
Issuance of Common Shares		1.0		-		1.4		-
Other Transactions, Net		24.1		-		12.8		-
Net Income Attributable to Noncontrolling Interests		-		1.9		-		1.9
Other Comprehensive Income		1.3		-		2.1		-
Balance as of End of Period	$	9,890.6	$	155.6	$	9,517.5	$	155.6


	For the Nine Months Ended
	September 30, 2014				September 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		603.6		-		614.4		-
Dividends on Common Shares		(372.2)		-		(346.9)		-
Dividends on Preferred Stock		(5.6)		(5.6)		(5.8)		(5.8)
Issuance of Common Shares		6.4		-		10.2		-
Other Transactions, Net		41.0		-		3.0		-
Net Income Attributable to Noncontrolling Interests		-		5.6		-		5.8
Other Comprehensive Income		5.9		-		5.5		-
Balance as of End of Period	$	9,890.6	$	155.6	$	9,517.5	$	155.6

14.

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 nine months ended September 30, 2014 or for the three months ended September 30, 2013. For the nine months ended September 30, 2013, there were 2,100 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 Nine Months Ended
(Millions of Dollars, except share information)		September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
Net Income Attributable to Controlling Interest		$	234.6	$	209.5	$	597.9	$	608.6

Weighted Average Common Shares Outstanding:
	Basic		316,340,691		315,291,346		315,941,904		315,191,752
	Dilutive Effect		1,214,234		926,893		1,244,586		869,379
	Diluted		317,554,925		316,218,239		317,186,490		316,061,131
Basic and Diluted EPS		$	0.74	$	0.66	$	1.89	$	1.93

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).

15.

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 nine months ended September 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 unregulated 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 September 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,502.6	$	109.2	$	262.5	$	211.2	$	(193.0)	$	1,892.5
Depreciation and Amortization		(71.7)		(16.4)		(37.4)		(13.8)		8.6		(130.7)
Other Operating Expenses		(1,141.5)		(98.4)		(74.2)		(192.4)		185.6		(1,320.9)
Operating Income/(Loss)		289.4		(5.6)		150.9		5.0		1.2		440.9
Interest Expense		(49.2)		(8.5)		(24.5)		(8.6)		1.0		(89.8)
Other Income, Net		9.3		0.1		2.7		226.4		(226.6)		11.9
Net Income Attributable to Controlling Interest	$	153.4	$	(9.9)	$	88.1	$	228.3	$	(225.3)	$	234.6


	For the Nine Months Ended September 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	4,350.4	$	737.5	$	721.4	$	568.1	$	(516.7)	$	5,860.7
Depreciation and Amortization		(309.9)		(51.1)		(111.4)		(28.3)		12.7		(488.0)
Other Operating Expenses		(3,343.9)		(586.2)		(211.5)		(534.1)		505.6		(4,170.1)
Operating Income		696.6		100.2		398.5		5.7		1.6		1,202.6
Interest Expense		(143.8)		(25.6)		(78.8)		(27.2)		3.2		(272.2)
Other Income, Net		13.6		0.2		6.9		657.9		(659.5)		19.1
Net Income Attributable to Controlling Interest	$	349.1	$	44.2	$	206.8	$	653.4	$	(655.6)	$	597.9
Cash Flows Used for Investments in Plant	$	480.1	$	120.6	$	469.9	$	46.9	$	-	$	1,117.5


	For the Three Months Ended September 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,508.6	$	97.1	$	234.1	$	212.5	$	(159.7)	$	1,892.6
Depreciation and Amortization		(159.6)		(16.4)		(34.5)		(11.2)		2.6		(219.1)
Other Operating Expenses		(1,064.1)		(89.4)		(73.4)		(206.8)		159.5		(1,274.2)
Operating Income/(Loss)		284.9		(8.7)		126.2		(5.5)		2.4		399.3
Interest Expense		(44.3)		(8.6)		(26.6)		(9.2)		1.2		(87.5)
Other Income, Net		5.5		0.5		2.9		312.1		(312.1)		8.9
Net Income/(Loss) Attributable to Controlling Interest	$	156.9	$	(10.4)	$	58.6	$	313.1	$	(308.7)	$	209.5


	For the Nine Months Ended September 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	4,104.4	$	613.0	$	721.5	$	650.4	$	(565.8)	$	5,523.5
Depreciation and Amortization		(488.7)		(50.5)		(100.9)		(52.0)		7.2		(684.9)
Other Operating Expenses		(2,952.4)		(483.6)		(199.1)		(599.0)		564.3		(3,669.8)
Operating Income/(Loss)		663.3		78.9		421.5		(0.6)		5.7		1,168.8
Interest Expense		(129.9)		(24.8)		(73.7)		(26.3)		4.1		(250.6)
Other Income, Net		12.6		0.7		8.5		866.2		(866.3)		21.7
Net Income Attributable to Controlling Interest	$	347.5	$	34.1	$	215.4	$	868.7	$	(857.1)	$	608.6
Cash Flows Used for Investments in Plant	$	501.9	$	91.2	$	458.2	$	22.5	$	-	$	1,073.8


The following table summarizes NU's segmented total assets:

	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
As of September 30, 2014	$	16,702.3	$	2,801.1	$	7,404.5	$	12,270.2	$	(11,195.8)	$	27,982.3
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 and Second Quarter 2014 Quarterly Reports on 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 period. The discussion below also includes non-GAAP financial measures referencing our third quarter and first nine months 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 third quarter and first nine months 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" and "Financial Condition and Business Analysis – Overview – Regulated Companies" in Management's Discussion and Analysis of Financial Condition and Results of Operations, 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 $234.6 million, or $0.74 per share, in the third quarter of 2014 and $597.9 million, or $1.89 per share, in the first nine months of 2014, compared with $209.5 million, or $0.66 per share, in the third quarter of 2013 and $608.6 million, or $1.93 per share, in the first nine months of 2013. Excluding integration costs, we earned $237.6 million, or $0.75 per share, in the third quarter of 2014 and $611.3 million, or $1.93 per share, in the first nine months of 2014, compared with $216.5 million, or $0.69 per share, in the third quarter of 2013, and $619.2 million, or $1.96 per share, in the first nine months of 2013.

Our electric distribution segment, which includes generation, earned $153.4 million, or $0.48 per share, in the third quarter of 2014 and $349.1 million, or $1.10 per share, in the first nine months of 2014, compared with earnings of $156.9 million, or $0.50 per share, in the third quarter of 2013 and $347.5 million, or $1.10 per share, in the first nine months of 2013.

Our transmission segment earned $88.1 million, or $0.28 per share, in the third quarter of 2014 and $206.8 million, or $0.65 per share, in the first nine months of 2014, compared with $58.6 million, or $0.18 per share, in the third quarter of 2013 and $215.4 million, or $0.68 per share, in the first nine months of 2013. The increase in the third quarter of 2014, as compared to the same period in 2013, was due primarily to the absence of an after-tax reserve of $14.3 million recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaint. The decrease in the first nine months of 2014, as compared to the same period in 2013, was due primarily to the after-tax reserve of $32.1 million recorded for the June 2014 FERC ROE orders, as compared to the $14.3 million reserve recorded in the third quarter of 2013.

Our natural gas distribution segment had a net loss of $9.9 million, or $0.03 per share, in the third quarter of 2014 and earnings of $44.2 million, or $0.14 per share, in the first nine months of 2014, compared with a net loss of $10.4 million, or $0.03 per share, in the third quarter of 2013 and earnings of $34.1 million, or $0.11 per share, in the first nine months of 2013.

NU parent and other companies earned $3 million, or $0.01 per share, in the third quarter of 2014 and had a net loss of $2.2 million in the first nine months of 2014, compared with earnings of $4.4 million, or $0.01 per share, in the third quarter of 2013 and $11.6 million, or $0.04 per share, in the first nine months of 2013. Third quarter and first nine months 2014 results reflect $3 million and $13.4 million, respectively, of after-tax integration costs. Third quarter and first nine months 2013 results reflect $7 million and $10.6 million, respectively, of after-tax integration costs.

Legislative, Regulatory and Other Items:

On September 16, 2014, NU and Spectra Energy Corp announced Access Northeast, a natural gas pipeline expansion project. Access Northeast will enhance the Algonquin and Maritimes pipeline systems using existing routes. NU and Spectra Energy Corp will have equal ownership interest in the project. The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.

On October 16, 2014, the FERC issued an order on the base ROE complaint filed by several parties in September 2011. The FERC order confirmed that the base ROE should be set at 10.57 percent and that a utility's total or maximum ROE inclusive of transmission incentive ROE adders should not exceed the top of the new zone of reasonableness (11.74 percent).

In October 2014, the NHPUC concluded its hearings in the Clean Air Project prudence review to determine the prudent costs of PSNH’s compliance with the law requiring scrubber installation. The NHPUC is expected to issue a decision on this matter by the end of 2014.

Liquidity:

Cash and cash equivalents totaled $41.7 million as of September 30, 2014, compared with $43.4 million as of December 31, 2013, while investments in property, plant and equipment totaled $1.1 billion in both the first nine months of 2014 and 2013.

Cash flows provided by operating activities totaled $1.4 billion in the first nine months of 2014, compared with $1.2 billion in the first nine months of 2013. The improved operating cash flows were due primarily to approximately $132 million in DOE Damages proceeds resulting from the spent nuclear fuel litigation received by CL&P, NSTAR Electric, PSNH and WMECO from the Yankee Companies, the absence of cash disbursements for major storm restoration costs and the decrease of approximately $264 million in Pension and PBOP Plan cash contributions, partially offset by changes in the timing of working capital items and higher income tax payments in 2014, as compared to the same period in 2013.

In the first nine months 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. Proceeds from these new issuances were used to repay approximately $525 million of existing long-term debt with remaining proceeds used to pay short-term borrowings.

In the first nine months of 2014, we had cash dividends on common shares of $356.1 million, compared with $341.7 million in the first nine months of 2013. On September 30, 2014, we paid a common dividend of $0.3925 per share, which was approved by our Board of Trustees on September 2, 2014, to shareholders of record as of September 15, 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 third quarter and first nine months of 2014 and 2013 is as follows:


	For the Three Months Ended September 30,								For the Nine Months Ended September 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)	$	234.6	$	0.74	$	209.5	$	0.66	$	597.9	$	1.89	$	608.6	$	1.93
Regulated Companies	$	231.6	$	0.73	$	205.1	$	0.65	$	600.1	$	1.89	$	597.0	$	1.89
NU Parent and Other Companies		6.0		0.02		11.4		0.04		11.2		0.04		22.2		0.07
Non-GAAP Earnings		237.6		0.75		216.5		0.69		611.3		1.93		619.2		1.96
Integration Costs (after-tax)		(3.0)		(0.01)		(7.0)		(0.03)		(13.4)		(0.04)		(10.6)		(0.03)
Net Income Attributable to Controlling Interest (GAAP)	$	234.6	$	0.74	$	209.5	$	0.66	$	597.9	$	1.89	$	608.6	$	1.93

Excluding the impact of integration costs, our third quarter 2014 earnings increased by $21.1 million, as compared to the third quarter of 2013. The increase was due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and the absence of an after-tax reserve of $14.3 million recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaint. Partially offsetting these favorable earnings impacts were higher property taxes, higher depreciation expense and lower retail electric sales volumes as a result of cooler summer weather in 2014, as compared to the same period in 2013.

Excluding the impact of integration costs, our first nine months 2014 earnings decreased by $7.9 million, as compared to the first nine months of 2013, due primarily to the absence in 2014 of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013, net of the favorable impact of a reduction in valuation allowance for state credits in the third quarter of 2014. Earnings were also unfavorably impacted by the after-tax reserve of $32.1 million related to the second quarter 2014 FERC ROE orders, as compared to the $14.3 million reserve related to the third quarter 2013 FERC ALJ initial decision in the FERC base ROE complaints. 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 due to higher depreciation expense at our regulated companies, higher property taxes and lower retail electric sales volumes as a result of cooler summer weather in 2014, as compared to the same period in 2013. Earnings were favorably impacted by lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and lower storm restoration costs, as well as higher firm natural gas sales volumes as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013.

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 and EPS for the third quarter and first nine months of 2014 and 2013 is as follows:


	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars, Except	2014				2013				2014				2013
Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share		Amount		Per Share
Electric Distribution	$	153.4	$	0.48	$	156.9	$	0.50	$	349.1	$	1.10	$	347.5	$	1.10
Transmission		88.1		0.28		58.6		0.18		206.8		0.65		215.4		0.68
Natural Gas Distribution		(9.9)		(0.03)		(10.4)		(0.03)		44.2		0.14		34.1		0.11
Net Income - Regulated Companies	$	231.6	$	0.73	$	205.1	$	0.65	$	600.1	$	1.89	$	597.0	$	1.89

Our electric distribution segment earnings decreased $3.5 million in the third quarter of 2014, as compared to the third quarter of 2013, due primarily to a 4.5 percent decrease in retail electric sales volumes as a result of cooler summer weather in 2014, higher depreciation expense and higher property taxes, partially offset by lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and lower vegetation management costs, all as compared to the same period in 2013.

Our electric distribution segment earnings increased $1.6 million in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and lower storm restoration costs. Partially offsetting these favorable earnings impacts were higher depreciation expense, higher property taxes, lower retail electric sales volumes as a result of cooler summer weather in 2014, and the absence in 2014 of regulatory interest income from stranded cost recoveries in 2013, all as compared to the same period in 2013.

Our transmission segment earnings increased $29.5 million in the third quarter of 2014, as compared to the third quarter of 2013, due primarily to the absence of the after-tax reserve of $14.3 million recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaint, a decrease in transmission segment state income tax expense, which includes the reduction in valuation allowance for state credits, and a higher transmission rate base as a result of an increased investment in our transmission infrastructure.

Our transmission segment earnings decreased $8.6 million in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to the after-tax reserve of $32.1 million recorded for the June 2014 FERC ROE orders, as compared to the $14.3 million reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints. These unfavorable impacts were partially offset by a decrease in transmission segment state income tax expense, which includes the reduction in valuation allowance for state credits, and a higher transmission rate base as a result of an increased investment in our transmission infrastructure.

Our natural gas distribution segment results improved by $0.5 million in the third quarter of 2014, as compared to the third quarter of 2013, due primarily to higher peak demand revenues and higher firm natural gas sales volumes resulting from additional natural gas heating customers.

Our natural gas distribution segment earnings increased $10.1 million in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to higher firm natural gas sales volumes and peak demand revenues resulting from colder weather in the first quarter of 2014 and additional natural gas heating customers.

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


	For the Three Months Ended September 30, 2014 Compared to 2013			For the Nine Months Ended September 30, 2014 Compared to 2013
	Sales Volumes (GWh)			Sales Volumes (GWh)		Percentage
NU – Electric	2014	2013	Percentage Decrease	2014	2013	Increase/ (Decrease)
Residential	5,656	6,102	(7.3)%	16,306	16,625	(1.9)%
Commercial	7,382	7,616	(3.1)%	20,838	21,064	(1.1)%
Industrial	1,517	1,529	(0.8)%	4,295	4,265	0.7 %
Total	14,555	15,247	(4.5)%	41,439	41,954	(1.2)%


Percentage	For the Three Months Ended September 30, 2014 Compared to 2013				For the Nine Months Ended September 30, 2014 Compared to 2013
Increase/(Decrease) Electric	CL&P	NSTAR Electric	PSNH	WMECO	CL&P	NSTAR Electric	PSNH	WMECO
Residential	(8.2)%	(6.6)%	(5.2)%	(9.2)%	(2.0)%	(2.4)%	(0.3)%	(2.6)%
Commercial	(3.3)%	(2.9)%	(2.6)%	(4.3)%	(1.1)%	(1.2)%	(0.4)%	(1.7)%
Industrial	(1.3)%	2.2 %	(1.5)%	(3.5)%	1.9 %	(0.4)%	1.5 %	(3.0)%
Total	(5.3)%	(3.8)%	(3.4)%	(6.2)%	(1.2)%	(1.5)%	- %	(2.3)%

A summary of our firm natural gas sales volumes 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 September 30, 2014 Compared to 2013			For the Nine Months Ended September 30, 2014 Compared to 2013
	Sales Volumes (million cubic feet)		Percentage	Sales Volumes (million cubic feet)
NU – Firm Natural Gas	2014	2013	Increase/ (Decrease)	2014	2013	Percentage Increase
Residential	2,487	2,407	3.3 %	27,468	24,392	12.6%
Commercial	4,565	4,673	(2.3)%	31,032	28,066	10.6%
Industrial	4,276	4,093	4.4 %	16,669	15,588	6.9%
Total	11,328	11,173	1.4 %	75,169	68,046	10.5%
Total, Net of Special Contracts ⁽¹⁾	10,200	10,155	0.4 %	71,645	64,815	10.5%


	For the Three Months Ended September 30, 2014 Compared to 2013		For the Nine Months Ended September 30, 2014 Compared to 2013
Percentage Increase/(Decrease)	Sales Volumes (million cubic feet)		Sales Volumes (million cubic feet)
Firm Natural Gas	Yankee Gas	NSTAR Gas	Yankee Gas	NSTAR Gas
Residential	(0.6)%	6.3 %	14.0%	11.6%
Commercial	1.7 %	(6.2)%	14.0%	7.5%
Industrial	4.6 %	4.0 %	7.3%	5.9%
Total	2.8 %	(0.5)%	11.8%	9.1%
Total, Net of Special Contracts ⁽¹⁾	1.3 %		12.1%

⁽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.

For the third quarter of 2014, our consolidated retail electric sales volumes, consisting of the retail electric sales volumes of CL&P, NSTAR Electric, PSNH, and WMECO, were lower, as compared to the same period in 2013, as a result of cooler summer weather in 2014. The third quarter of 2014 cooling degree days were 12 percent lower in Connecticut and western Massachusetts, 15 percent lower in the Boston metropolitan area, and 24 percent lower in New Hampshire, as compared to the third quarter of 2013. Weather-normalized retail electric sales volumes (based on 30-year average temperatures) decreased 2.3 percent in the third quarter of 2014, as compared to the third quarter of 2013. We believe the decrease was due primarily to increased conservation efforts by our residential and commercial customer classes, which are driven by the energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.

For the first nine months of 2014, our consolidated retail electric sales volumes were lower, as compared to the same period in 2013, due primarily to cooler summer weather in 2014, partially offset by colder weather in the first quarter of 2014. The first nine months of 2014 cooling degree days were 14 percent lower in Connecticut and western Massachusetts, 16 percent lower in the Boston metropolitan area, and 24 percent lower in New Hampshire, as compared to the first nine months of 2013. Weather-normalized retail electric sales volumes decreased 0.9 percent in the first nine months of 2014, as compared to the first nine months 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 volumes 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 third quarter and first nine months of 2014, consolidated firm natural gas sales volumes, consisting of the firm natural gas sales volumes of Yankee Gas and NSTAR Gas, were higher, as compared to the third quarter and first nine months of 2013, due primarily to colder weather in the first quarter of 2014, as compared to the same period in 2013, and increased customer growth in the first nine months of 2014, as compared to the same period in 2013. The third quarter and first nine months of 2014 weather-normalized NU consolidated total firm natural gas sales volumes increased 1 percent and 3.6 percent, respectively, as compared to the same periods in 2013.

NU Parent and Other Companies: NU parent and other companies, which includes our unregulated businesses, earned $3 million and had a net loss of $2.2 million in the third quarter and first nine months of 2014, respectively, compared with earnings of $4.4 million and $11.6 million in the third quarter and first nine months of 2013, respectively. Excluding the impact of integration costs, NU parent and other companies earned $6 million and $11.2 million in the third quarter and first nine months of 2014, respectively, compared with $11.4 million and $22.2 million in the third quarter and first nine months of 2013, respectively. The earnings decrease for the first nine months of 2014 was due primarily to the absence in 2014 of the favorable impact from the resolution of the Connecticut state income tax audit, which provided a $5.8 million earnings benefit to the first nine months of 2013.

Liquidity

Consolidated: Cash and cash equivalents totaled $41.7 million as of September 30, 2014, compared with $43.4 million as of December 31, 2013.

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

On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds.

On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.

Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint $1.45 billion revolving credit facility for one 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 September 30, 2014 and December 31, 2013, NU had $964.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $485.5 million and $435.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of September 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 September 30, 2014, there were intercompany loans from NU of $105.4 million to CL&P, $153.3 million to PSNH and $13.2 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.

Cash flows provided by operating activities totaled $1.4 billion in the first nine months of 2014, compared with $1.2 billion in the first nine months of 2013. The improved operating cash flows were due primarily to approximately $132 million in DOE Damages proceeds resulting from the spent nuclear fuel litigation received by CL&P, NSTAR Electric, PSNH and WMECO from the Yankee Companies, the absence of cash disbursements for major storm restoration costs and the decrease of approximately $264 million in Pension and PBOP Plan cash contributions, partially offset by changes in the timing of working capital items and income tax payments of $256 million for the first nine months of 2014, compared to $34 million for the same period in 2013. For further information on the spent nuclear fuel litigation, see Note 9C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Quarterly Report on Form 10-Q.

In the first nine months of 2014, CL&P, NSTAR Electric, PSNH, and WMECO paid $128.4 million, $253 million, $49.5 million, and $49 million, respectively, in common dividends to NU parent.

Investments in Property, Plant and Equipment on the 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 nine months of 2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.1 billion, $371.7 million, $309.2 million, $170.1 million, and $82.5 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 $1.1 billion in the first nine months of both 2014 and 2013. These amounts included $40.9 million and $14.7 million in the first nine months of 2014 and 2013, respectively, related to our corporate service companies, NUSCO and RRR.

Access Northeast: On September 16, 2014, NU and Spectra Energy Corp announced Access Northeast, a natural gas pipeline expansion project. Access Northeast will enhance the Algonquin and Maritimes pipeline systems using existing routes and is expected to be capable of delivering approximately one billion cubic feet of natural gas per day to New England. NU and Spectra Energy Corp will have equal ownership interest in the project with the option of additional investors joining in the future. The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.

Transmission Business: Overall, transmission business capital expenditures increased by $33.5 million in the first nine months of 2014, as compared to the first nine months of 2013. A summary of transmission capital expenditures by company for the first nine months of 2014 and 2013 is as follows:


	For the Nine Months Ended September 30,
(Millions of Dollars)	2014		2013
CL&P	$	201.5	$	133.5
NSTAR Electric		111.1		140.0
PSNH		76.9		58.0
WMECO		50.1		62.0
NPT		19.4		32.0
Total Transmission Segment	$	459.0	$	425.5

NEEWS: GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013. As of September 30, 2014, CL&P and WMECO had placed $640 million in service with minimal remaining close-out activities continuing throughout the remainder of 2014.

The Interstate Reliability Project (IRP) is the second major NEEWS project. It 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. As of May 2014, all three states have issued siting approvals. The Army Corps of Engineers issued its permit on the project (the last required project permit) 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 was approximately 62 percent complete as of September 30, 2014.

The Greater Hartford Central Connecticut Study (GHCC) includes the reassessment of the Central Connecticut Reliability Project and 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 that are expected to cost approximately $350 million and be placed in service from 2016 through 2018. We expect to begin work on the initial solutions in late 2015 and complete GHCC-related work in 2018.

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

Through September 30, 2014, CL&P and WMECO capitalized $323.6 million and $573.6 million, respectively, in costs associated with NEEWS, of which $70.8 million and $6.6 million, respectively, were capitalized in the first nine months of 2014. Included in the NEEWS amounts are costs for IRP, of which CL&P capitalized $140.9 million in costs through September 30, 2014, and $67.9 million related to costs capitalized in the first nine months 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 DOE continues to work on the draft Environmental Impact Statement (EIS) for Northern Pass. This includes a review of our proposed route and various alternative routes. We now expect the DOE to issue the draft EIS in March 2015. We expect to file the state permit application in the second quarter of 2015 after receipt of the draft EIS. The expected $1.4 billion project is subject to comprehensive federal and state public permitting processes and is now expected to be operational in the second half of 2018.

Greater Boston Reliability Solutions: 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. For a portion of these new transmission initiatives, ISO-NE and state regulators must decide between two alternative transmission solutions. We expect ISO-NE to select the preferred solution in late 2014 or early 2015. If ISO-NE selects our solution, which is the lower overall capital cost plan, then our investments are estimated to be $489 million. If the alternate plan is chosen, then we still expect to invest approximately $356 million.

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


	For the Nine Months Ended September 30,
(Millions of Dollars)	2014		2013
CL&P:
Basic Business	$	70.2	$	42.7
Aging Infrastructure		81.1		116.6
Load Growth		49.7		56.9
Total CL&P		201.0		216.2
NSTAR Electric:
Basic Business		75.4		84.6
Aging Infrastructure		76.0		75.0
Load Growth		25.8		22.5
Total NSTAR Electric		177.2		182.1
PSNH:
Basic Business		33.1		13.7
Aging Infrastructure		24.2		32.2
Load Growth		21.4		18.3
Total PSNH		78.7		64.2
WMECO:
Basic Business		6.2		5.3
Aging Infrastructure		10.2		16.7
Load Growth		3.6		5.7
Total WMECO		20.0		27.7
Total - Electric Distribution (excluding Generation)		476.9		490.2
PSNH Generation		11.3		5.5
WMECO Generation		7.5		0.9
Total - Natural Gas		138.9		126.7
Total Electric and Natural Gas Distribution Segment	$	634.6	$	623.3

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:

Third Complaint: On July 31, 2014, a third complaint was filed at FERC (the "third complaint") by most of the complainants to the first and second complaints, claiming that the base ROE and incentive adders exceed the range of permissible ROEs, requesting FERC to reduce the NETO’s base ROE prospectively from the FERC order date, and seeking refunds for the 15-month period beginning August 1, 2014 (the "third complaint refund period"). FERC has taken no action on this complaint to date. At this time, the Company cannot determine the outcome of this complaint.


	NU
		Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total
1^st Complaint - Base ROE	$	23.7	$	1.2	$	24.9
2^nd Complaint - Base ROE		-		27.4		27.4
Incentive ROE (1^st and 2^nd Complaint)		-		23.8		23.8
Cumulative Reserve	$	23.7	$	52.4	$	76.1

FERC Order No. 1000: On August 15, 2014, the D.C. Circuit Court of Appeals upheld FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission. FERC has not yet ruled on the comprehensive compliance filings made in November of 2013 by the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO. We cannot predict the final outcome or impact on us; however implementation of FERC’s goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects. While the FERC Orders may bring new challenges, we believe there are also opportunities for us to compete for transmission reliability projects outside of our service territories.

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 nine months 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. The application included an increase to base distribution rates, as well as increases for the annual recovery of previously approved 2011 and 2012 deferred storm restoration costs and previously approved electric system resiliency costs. Hearings were held in late August through the end of September 2014, followed by the legal briefing process. After the briefing process, CL&P updated its requested increase to reflect a reduction to the storm cost recovery amounts. The reduction primarily relates to applying the impact of the $65.4 million DOE Phase II Damages proceeds received on June 1, 2014 to the total deferred storm restoration costs of $365 million, as ordered by PURA on June 17, 2014. A final decision is expected in December 2014. A summary of the annual increase in distribution rates requested in the initial application and the current request is as follows:


(Millions of Dollars)	Base Distribution Rate Increase		2011 and 2012 Storm Cost Recovery		System Resiliency Cost Recovery		Total Distribution Rate Increase
Initial Application	$	116.7	$	89.5	$	25.3	$	231.5
Adjustments		5.7		(16.2)		-		(10.5)
Current Request	$	122.4	$	73.3	$	25.3	$	221.0

Massachusetts:

DPU Storm Penalties: In December 2012, in separate orders issued by the DPU, the DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, related to the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm, which were refunded to their customers. In December 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated.

On September 4, 2014, the SJC vacated $2 million of NSTAR Electric's $4.1 million penalties. The SJC found that certain of the penalties were not supported by substantial evidence. The remaining penalties, as well as the $2 million in penalties related to WMECO, were upheld.

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.

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 Legislature enacted changes to the laws governing divestiture of PSNH's generation assets, effective September 30, 2014. The new law 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. The NHPUC opened its docket DE 14-238 on September 16, 2014 and a Prehearing Conference was held on October 2, 2014. A progress report from the NHPUC must be made by March 31, 2015. The law also gives 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 law also clarified 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 and the PSNH Restructuring Settlement Agreement approved in 2000 require that the NHPUC provide recovery of any stranded costs by PSNH. We continue to believe generation investments and prudently-incurred costs are probable of recovery.

Clean Air Project Prudence Proceeding: The Clean Air Project, which involved the installation of wet scrubber technology at PSNH’s Merrimack coal-fired generation station in Bow, New Hampshire, was placed in service in September 2011. In November 2011, the NHPUC opened a docket to review the Clean Air Project, including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. In April 2012, the NHPUC issued an order authorizing temporary rates to recover a significant portion of the Clean Air Project costs. The docket will remain open to conduct a comprehensive prudence review of the Clean Air Project and the establishment of permanent rates. The temporary rates will remain in effect until permanent rates allowing full recovery of all prudently incurred costs are approved. At that time, the NHPUC will reconcile recoveries collected under the temporary rates with approved permanent rates.

The NHPUC concluded its hearings in October 2014 to determine the prudent costs of PSNH’s compliance with the law requiring scrubber installation. The NHPUC is expected to issue a decision on this matter by the end of 2014. We continue to believe that we were prudent in the undertaking and completion of the Clean Air Project. While we cannot predict with certainty the outcome of the Clean Air Project prudence review, we believe all costs were incurred appropriately and 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.

NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU on October 31, 2014. The program accelerates the replacement of gas distribution facilities composed of leak prone materials to eliminate leak prone infrastructure in the system within 25 years. The GSEP includes a new tariff that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor to be approved by the DPU.

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: 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 9B, "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 in the statements of income for NU for the three and nine months ended September 30, 2014 and 2013 included in this Quarterly Report on Form 10-Q:


			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
							Increase/								Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Operating Revenues			$	1,892.5	$	1,892.6	$	(0.1)	-	%	$	5,860.7	$	5,523.5	$	337.2	6.1	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			716.6		645.9		70.7	10.9			2,319.0		1,882.0		437.0	23.2
	Operations and Maintenance			344.1		386.7		(42.6)	(11.0)			1,069.0		1,090.0		(21.0)	(1.9)
	Depreciation			153.2		149.1		4.1	2.7			456.2		463.6		(7.4)	(1.6)
	Amortization of Regulatory Assets/(Liabilities), Net			(22.5)		70.0		(92.5)	(a)			31.8		178.7		(146.9)	(82.2)
	Amortization of Rate Reduction Bonds			-		-		-	-			-		42.6		(42.6)	(100.0)
	Energy Efficiency Programs			118.7		106.1		12.6	11.9			360.2		306.0		54.2	17.7
	Taxes Other Than Income Taxes			141.5		135.5		6.0	4.4			421.9		391.8		30.1	7.7
		Total Operating Expenses		1,451.6		1,493.3		(41.7)	(2.8)			4,658.1		4,354.7		303.4	7.0
Operating Income				440.9		399.3		41.6	10.4			1,202.6		1,168.8		33.8	2.9
Interest Expense				89.7		87.5		2.2	2.5			272.2		250.6		21.6	8.6
Other Income, Net				11.8		8.9		2.9	32.6			19.0		21.6		(2.6)	(12.0)
Income Before Income Tax Expense				363.0		320.7		42.3	13.2			949.4		939.8		9.6	1.0
Income Tax Expense				126.5		109.3		17.2	15.7			345.9		325.4		20.5	6.3
Net Income				236.5		211.4		25.1	11.9			603.5		614.4		(10.9)	(1.8)
Net Income Attributable to Noncontrolling Interests				1.9		1.9		-	-			5.6		5.8		(0.2)	(3.4)
Net Income Attributable to Controlling Interest			$	234.6	$	209.5	$	25.1	12.0	%	$	597.9	$	608.6	$	(10.7)	(1.8)	%

Operating Revenues
			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
							Increase/								Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Electric Distribution			$	1,502.6	$	1,508.6	$	(6.0)	(0.4)	%	$	4,350.4	$	4,104.4	$	246.0	6.0	%
Natural Gas Distribution				109.2		97.1		12.1	12.5			737.5		613.0		124.5	20.3
	Total Distribution			1,611.8		1,605.7		6.1	0.4			5,087.9		4,717.4		370.5	7.9
Transmission				262.5		234.1		28.4	12.1			721.4		721.5		(0.1)	-
	Total Regulated Companies			1,874.3		1,839.8		34.5	1.9			5,809.3		5,438.9		370.4	6.8
Other and Eliminations				18.2		52.8		(34.6)	(65.5)			51.4		84.6		(33.2)	(39.2)
Total Operating Revenues			$	1,892.5	$	1,892.6	$	(0.1)	-	%	$	5,860.7	$	5,523.5	$	337.2	6.1	%

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

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

			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
							Increase/								Increase/
			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Retail Electric Sales Volumes in GWh				14,555		15,247		(692)	(4.5)	%		41,439		41,954		(515)	(1.2)	%
Firm Natural Gas Sales Volumes in Million Cubic Feet				11,328		11,173		155	1.4			75,169		68,046		7,123	10.5

Three Months Ended:

In the third quarter of 2014 compared to the third quarter of 2013, Operating Revenues remained essentially flat.

Electric base distribution revenues decreased $22.6 million compared to the same period in 2013, reflecting a 4.5 percent decrease in retail electric sales volumes. The decrease in sales volumes reflects the cooler summer weather in 2014 as well as the impact of our utility-sponsored energy efficiency programs. There was an increase in revenues related to the 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 have no impact on earnings. Firm natural gas sales volumes increased 1.4 percent from the third 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. CL&P and NSTAR Electric bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. We recognized $15.8 million of lost base revenue in the third quarter of 2014 compared to $5.5 million during the same period of 2013.

Transmission revenues increased in the third quarter of 2014, as compared to the third quarter of 2013, as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure.

Nine Months Ended:

In the first nine months of 2014 compared to the first nine months of 2013, Operating Revenues increased $337.2 million.

The most significant factor in the revenue increase was the overall impact of the recovery of costs associated with the procurement of energy supply. The costs incurred to procure energy were significantly higher in 2014 than in 2013. 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 electric energy purchased for our retail electric customers. Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings.

Firm base natural gas revenues increased $25.9 million reflecting an increase of approximately 10.5 percent in firm natural gas sales volumes. 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 total firm natural gas sales volumes (based on 30-year average temperatures) increased 3.6 percent in the first nine months of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.

In the first nine months of 2014, base electric distribution revenues decreased $16 million, compared to the first nine months of 2013. This decrease reflects a 1.2 percent reduction in sales volumes. The decrease in sales volumes reflects the cooler summer weather in 2014 as well as the impact of our utility-sponsored energy efficiency programs, partially offset by colder winter weather in the first quarter of 2014. Weather-normalized retail electric sales volumes decreased 0.9 percent in the first nine months of 2014, as compared to the same period in 2013, reflecting the impact of our utility-sponsored energy efficiency programs.

CL&P and NSTAR Electric bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. We recognized $31.9 million of lost base revenue in the first nine months of 2014 compared to $14.6 million during the same period of 2013.

Transmission revenues remained essentially flat in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints. 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.

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energy supply costs are recovered from customers in rates through cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the following:


	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Electric Distribution	$	87.9	$	366.0
Natural Gas Distribution		10.6		79.7
Transmission		-		(3.2)
Other and Eliminations		(27.8)		(5.5)
Total Purchased Power, Fuel and Transmission	$	70.7	$	437.0

The increase in purchased power at the electric and natural gas distribution businesses were driven by the 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 electric energy purchased for our retail electric customers.

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric and natural gas distribution rates (and therefore impact earnings). Operations and Maintenance decreased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the following:


	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Base Electric Distribution:
Labor and other employee-related costs, including pension costs	$	(18.8)	$	(62.3)
Implementation of a new outage restoration program at CL&P		4.8		9.7
Vegetation management costs		(4.7)		(0.9)
Storm restoration costs		(1.6)		(10.1)
Other operations and maintenance		(4.1)		21.6
Total Base Electric Distribution		(24.4)		(42.0)
Total Base Natural Gas Distribution		(0.6)		2.3
Total Base Electric and Natural Gas Distribution		(25.0)		(39.7)
Total Tracked costs (Transmission and Electric and Natural Gas Distribution)		(3.6)		19.9
Total Distribution and Transmission		(28.6)		(19.8)
Other and eliminations:
Integration and severance costs		(7.0)		4.5
All other (including eliminations)		(7.0)		(5.7)
Total Operations and Maintenance	$	(42.6)	$	(21.0)

Depreciation increased for the three months ended September 30, 2014, as compared to the same period in 2013 due primarily to higher utility plant balances resulting from completed construction projects placed into service ($8.8 million), partially offset by a decrease in CYAPC and YAEC decommissioning costs, which do not impact earnings ($4.7 million). For the nine months ended September 30, 2014, depreciation expense decreased due primarily to a decrease in the CYAPC and YAEC decommissioning costs, which do not impact earnings ($29.7 million), partially offset by an increase related to higher utility plant balances resulting from completed construction projects placed into service ($22.3 million).

Amortization of Regulatory Assets/(Liabilities), Net, which are tracked costs, include certain regulatory-approved tracking mechanisms. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings. Amortization of Regulatory Assets/(Liabilities), Net, decreased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the following:


	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
NSTAR Electric (primarily deferred transition costs)	$	(87.8)	$	(174.2)
PSNH (primarily default energy service charge)		(10.0)		(15.9)
CL&P (primarily energy supply and energy-related costs)		13.1		51.4
WMECO (primarily deferred transition costs)		(7.1)		(7.2)
Other		(0.7)		(1.0)
Total Amortization of Regulatory Assets/(Liabilities), Net	$	(92.5)	$	(146.9)

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

Energy Efficiency Programs, which are tracked costs, increased for the three and nine months ended September 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 as a result of 2013 legislative action, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric.

Taxes Other Than Income Taxes increased for the three and nine months ended September 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, combined with a decrease and increase, respectively, in the Connecticut gross earnings tax for the three months and nine months ended, attributable to fluctuations in retail revenues.

Interest Expense increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, 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), lower interest income from a decrease in the recovery of previously deferred transition costs ($0.5 million and $8.2 million, respectively), and an increase in interest on long-term debt ($0.3 million and $3.9 million, respectively) as a result of new debt issuances in the first and second quarters of 2014.

Other Income, Net increased for the three months ended September 30, 2014, as compared to the same period in 2013, due primarily to a gain on the sale of land ($4.5 million), and higher AFUDC related to equity funds ($3.8 million), partially offset by lower unrealized gains on assets supporting the deferred compensation plans ($3.1 million) and the absence in 2014 of an insurance policy claim received in 2013 ($2.6 million). Other Income, Net decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($6.5 million), and the absence in 2014 of an insurance policy claim received in 2013 ($2.6 million), partially offset by higher AFUDC related to equity funds ($3.8 million), and a net gain on the sale of land ($4.5 million).

Income Tax Expense increased for the three months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($14.9 million), and higher state taxes, which includes the reduction in valuation allowance for state credits, and various other impacts ($2.3 million).

Income Tax Expense increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($6.5 million), and higher state taxes, which includes the reduction in valuation allowance for state credits, and various other impacts ($14 million).

RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY

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


			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
							Increase/								Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Operating Revenues			$	695.6	$	648.4	$	47.2	7.3	%	$	2,017.6	$	1,841.8	$	175.8	9.5	%
Operating Expenses:
	Purchased Power and Transmission			255.8		253.1		2.7	1.1			737.0		667.3		69.7	10.4
	Operations and Maintenance			127.2		127.1		0.1	0.1			368.6		359.7		8.9	2.5
	Depreciation			46.9		44.8		2.1	4.7			139.6		132.3		7.3	5.5
	Amortization of Regulatory Assets, Net			13.1		-		13.1	100.0			62.6		11.2		51.4	(a)
	Energy Efficiency Programs			41.4		24.5		16.9	69.0			119.4		68.2		51.2	75.1
	Taxes Other Than Income Taxes			65.0		65.0		-	-			194.1		182.7		11.4	6.2
		Total Operating Expenses		549.4		514.5		34.9	6.8			1,621.3		1,421.4		199.9	14.1
Operating Income				146.2		133.9		12.3	9.2			396.3		420.4		(24.1)	(5.7)
Interest Expense				38.7		35.3		3.4	9.6			110.4		99.0		11.4	11.5
Other Income, Net				6.4		3.9		2.5	64.1			10.6		10.9		(0.3)	(2.8)
Income Before Income Tax Expense				113.9		102.5		11.4	11.1			296.5		332.3		(35.8)	(10.8)
Income Tax Expense				30.0		36.2		(6.2)	(17.1)			95.9		113.1		(17.2)	(15.2)
Net Income			$	83.9	$	66.3	$	17.6	26.5	%	$	200.6	$	219.2	$	(18.6)	(8.5)	%

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

Operating Revenues
CL&P's retail sales volumes were as follows:

			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
			2014		2013		Decrease		Percent		2014		2013		Decrease		Percent
Retail Sales Volumes in GWh				5,791		6,119		(328)	(5.3)	%		16,790		16,993		(203)	(1.2)	%

CL&P's Operating Revenues increased in the third quarter of 2014, as compared to the same period 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 electric energy purchased for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings. The increase was also driven by a higher level of recovery related to CL&P's energy efficiency programs, which has no impact on earnings, as a result of 2013 legislative action. Partially offsetting this increase was a decrease in retail sales volumes in the third quarter of 2014, as compared to the same period in 2013, as a result of cooler summer weather in 2014.

CL&P's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013. The increase primarily reflects 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 electric energy purchased for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings. The increase was also driven by a higher level of recovery related to CL&P's energy efficiency programs, which has no impact on earnings, as a result of 2013 legislative action. Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints. 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.

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P's customers. These energy supply costs are recovered from customers in PURA-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the following:


	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Purchased Power Costs	$	42.4	$	111.2
Transmission Costs		(34.4)		(22.6)
Other		(5.3)		(18.9)
Total Purchased Power and Transmission	$	2.7	$	69.7

Included in Purchased Power are the costs associated with CL&P's generation services charge (GSC) and deferred energy costs. The GSC recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. The increase in purchased power was due primarily to higher average supply prices and increased load as a result of customers returning to standard offer from third party suppliers. The decrease in transmission costs was the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

Tracked costs, which have no earnings impact, increased $4.5 million, which was primarily attributable to higher hardship and other tracked bad debt expense. This increase was offset by a decrease in costs that impact earnings of $4.4 million, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower routine vegetation management costs, partially offset by an increase in costs for the implementation of a new outage restoration program that began in the second quarter of 2014.

Operations and Maintenance increased for the nine months ended September 30, 2014, as compared to the same period in 2013, driven by a $14.2 million increase in tracked costs, which have no earnings impact, which was primarily attributable to higher hardship and other tracked bad debt expense. Partially offsetting this increase was a $5.3 million decrease in costs that impact earnings, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower storm restoration costs, partially offset by an increase in costs for the implementation of a new outage restoration program that began in the second quarter of 2014.

Depreciation increased for the three and nine months ended September 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 nine months ended September 30, 2014, as compared to the same periods in 2013. Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxes did not materially change for the three months ended September 30, 2014 and increased for the nine months ended September 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, and a decrease and increase, respectively, in the Connecticut gross earnings tax for the three months and nine months ended attributable to fluctuations in retail revenues.

Interest Expense increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, 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), an increase in interest on long-term debt ($1.9 million and $4.1 million, respectively) as a result of a new debt issuance in April 2014, and an increase in regulatory interest due to the refund of the DOE proceeds in the third quarter of 2014 ($1.2 million).

Other Income, Net increased for the three months ended September 30, 2014, as compared to the same period in 2013, due primarily to a gain on the sale of land ($4.5 million), higher AFUDC related to equity funds ($0.4 million), partially offset by lower unrealized gains on the assets supporting the deferred compensation plans ($2.4 million).

Income Tax Expense decreased for the three months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower state tax expense, which includes the reduction in valuation allowance for state credits, and various other impacts ($10.2 million), partially offset by higher pre-tax earnings ($4 million).

Income Tax Expense decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower pre-tax earnings ($11.1 million) and lower state taxes, which includes the reduction in valuation allowance for state credits, and various other impacts ($6.1 million).

EARNINGS SUMMARY

CL&P's third quarter 2014 earnings were higher than the same period in 2013 due primarily to the absence of an after-tax reserve of $7.7 million recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints, lower income tax expense due to the reduction in valuation allowance, and a decrease in operations and maintenance costs attributable to lower employee-related costs. Partially offsetting these favorable earnings impacts were lower retail electric sales volumes as a result of cooler summer weather in 2014, as compared to the same period in 2013, higher depreciation expense and higher property taxes.

For the nine months ended September 30, 2014, CL&P's earnings decreased, as compared to the same period in 2013, due primarily to the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($10.8 million increase), higher property tax expense and higher interest expense. Partially offsetting these unfavorable earnings impacts were lower income tax expense due to the reduction in valuation allowance and a decrease in operations and maintenance costs primarily attributable to lower employee-related costs.

LIQUIDITY

CL&P had cash flows provided by operating activities of $483 million in the first nine months of 2014, compared with $308.6 million in the first nine months of 2013. The improved operating cash flows were due primarily to $68.6 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs, an increase in regulatory overrecoveries, partially offset by changes in working capital items, an unfavorable cash flow impact relating to income tax payments of $85.3 million in the first nine months of 2014, as compared to income tax payments of $41.2 million in the first nine months of 2013.

Effective July 23, 2014, NU parent and certain of its subsidiaries, including CL&P, extended the expiration date of their joint $1.45 billion revolving credit facility for one 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 September 30, 2014 and December 31, 2013, there were intercompany loans from NU parent of $105.4 million and $287.3 million, respectively, to CL&P.

On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds.

On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.

Financing activities in the first nine months of 2014 included $128.4 million in common stock dividends paid to NU parent.

RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY

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


			For the Nine Months Ended September 30,
(Millions of Dollars)			2014		2013		Increase/		Percent
(Millions of Dollars)			2014		2013		(Decrease)		Percent
Operating Revenues			$	1,955.6	$	1,916.6	$	39.0	2.0	%
Operating Expenses:
	Purchased Power and Transmission			879.8		659.1		220.7	33.5
	Operations and Maintenance			244.6		277.3		(32.7)	(11.8)
	Depreciation			141.0		136.3		4.7	3.4
	Amortization of Regulatory Assets/(Liabilities), Net			(0.9)		173.3		(174.2)	(a)
	Amortization of Rate Reduction Bonds			-		15.1		(15.1)	(100.0)
	Energy Efficiency Programs			145.5		161.2		(15.7)	(9.7)
	Taxes Other Than Income Taxes			99.1		95.3		3.8	4.0
		Total Operating Expenses		1,509.1		1,517.6		(8.5)	(0.6)
Operating Income				446.5		399.0		47.5	11.9
Interest Expense				59.1		51.6		7.5	14.5
Other Income, Net				3.0		3.3		(0.3)	(9.1)
Income Before Income Tax Expense				390.4		350.7		39.7	11.3
Income Tax Expense				156.6		137.5		19.1	13.9
Net Income			$	233.8	$	213.2	$	20.6	9.7	%

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

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

			For the Nine Months Ended September 30,
			2014		2013		Decrease		Percent
Retail Sales Volumes in GWh				15,958		16,204		(246)	(1.5)	%

NSTAR Electric's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months 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 electric energy purchased for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints. 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. Additionally, transition 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 decreased in the first nine months of 2014, as compared to the same period in 2013, which was due primarily to cooler summer weather and customer savings due to the impact of 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 nine months of 2014, including the impact from the recognition of lost base revenues, base distribution revenues were flat, compared to the first nine months of 2013.

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of NSTAR Electric's customers. These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms which have no impact on earnings (tracked costs). Purchased Power and Transmission increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to the following:


(Millions of Dollars)	Increase
Purchased Power Costs	$	167.6
Transmission Costs		49.0
Other		4.1
Total Purchased Power and Transmission	$	220.7

The increase in purchased power was due primarily to higher energy supply prices. The increase in transmission costs was due primarily to higher RNS expense.

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, driven by a $36.9 million reduction in costs that impact earnings, which was primarily attributable to lower labor and other employee-related costs. Partially offsetting this decrease was a $4.2 million increase in tracked costs, which have no earnings impact, which was primarily attributable to an increased level of recovery of deferred storm costs.

Depreciation increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets/(Liabilities), Net, reflects a decrease in the recovery of previously deferred tracked transition costs for the nine months ended September 30, 2014, as compared to the same period in 2013. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.

Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due to the maturity of the RRBs in March 2013.

Energy Efficiency Programs, which are tracked costs, decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to a decrease in the amortization of previously deferred costs. This was partially offset by an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU.

Taxes Other Than Income Taxes increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.

Interest Expense increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower interest income from a decrease in the recovery of previously deferred transition costs ($8.7 million), partially offset by a decrease in interest on long-term debt ($0.8 million).

Income Tax Expense increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($13.8 million) and higher state taxes ($5.3 million).

EARNINGS SUMMARY

For the nine months ended September 30, 2014, NSTAR Electric's earnings increased, as compared to the same period in 2013, due primarily to lower operations and maintenance costs primarily attributable to lower employee-related costs. Partially offsetting the favorable earnings impact were the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($2.7 million increase), higher interest expense, higher depreciation expense and higher property tax expense.

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities of $517.5 million in the first nine months of 2014, compared with $317.6 million in the first nine months of 2013. The improved operating cash flows were due primarily to the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard, collections of accounts receivable from affiliated companies, $30.2 million in DOE Damages proceeds in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation and the absence of Pension Plan cash contributions in the first nine months of 2014, as compared to contributions of $82 million in the first nine months 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 and an increase in income taxes paid.

Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million, respectively, of available borrowing capacity. The weighted-average interest rate on these borrowings as of September 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 in the statements of income for PSNH for the nine months ended September 30, 2014 and 2013 included in this Quarterly Report on Form 10-Q:


			For the Nine Months Ended September 30,
								Increase/
(Millions of Dollars)			2014		2013			(Decrease)		Percent
Operating Revenues			$	735.1	$		708.6	$	26.5	3.7	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			248.0			197.8		50.2	25.4
	Operations and Maintenance			198.0			191.6		6.4	3.3
	Depreciation			73.2			68.4		4.8	7.0
	Amortization of Regulatory Assets/(Liabilities), Net			(17.6)			(1.7)		(15.9)	(a)
	Amortization of Rate Reduction Bonds			-			19.7		(19.7)	(100.0)
	Energy Efficiency Programs			10.9			11.0		(0.1)	(0.9)
	Taxes Other Than Income Taxes			53.1			52.7		0.4	0.8
		Total Operating Expenses		565.6			539.5		26.1	4.8
Operating Income				169.5			169.1		0.4	0.2
Interest Expense				34.0			34.2		(0.2)	(0.6)
Other Income, Net				1.7			2.4		(0.7)	(29.2)
Income Before Income Tax Expense				137.2			137.3		(0.1)	(0.1)
Income Tax Expense				52.2			52.8		(0.6)	(1.1)
Net Income			$	85.0	$		84.5	$	0.5	0.6	%

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

Operating Revenues
PSNH's retail sales volumes were as follows:

			For the Nine Months Ended September 30,
			2014		2013			Decrease		Percent
Retail Sales Volumes in GWh				5,970		5,971			(1)	-	%

PSNH's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013, due primarily 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 electric energy purchased 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 $6.7 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 in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints. 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.

Purchased Power, Fuel and Transmission expense includes costs associated with PSNH's generation of electricity as well as purchasing electricity on behalf of its customers. These energy supply costs are recovered from customers in NHPUC-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Generation Fuel Costs	$	43.0
Transmission Costs		12.3
Purchased Power Costs		(11.5)
Other		6.4
Total Purchased Power, Fuel and Transmission	$	50.2

The increase in generation fuel costs was due primarily to an increase in the amount of electricity generated by PSNH facilities. The decrease in purchased power costs was a result of purchasing less power due to increased PSNH generation. 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.

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased for the nine months ended September 30, 2014, as compared to the same period in 2013, driven by a $6.2 million increase in tracked costs, which have no earnings impact, which was primarily attributable to higher operations and maintenance costs at the generation business due to the timing of planned outages, partially offset by lower labor and other employee-related costs, including pension costs.

Amortization of Regulatory Assets/(Liabilities), Net, reflects a decrease in the recovery of the default energy service charge and other amortizations for the nine months ended September 30, 2014, as compared to the same period in 2013. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.

Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due to the maturity of the RRBs in May 2013.

Income Tax Expense decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to various tax impacts ($0.6 million).

EARNINGS SUMMARY

For the nine months ended September 30, 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. Partially offsetting this favorable earnings impact were the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($0.6 million increase), and higher depreciation expense.

LIQUIDITY

PSNH had cash flows provided by operating activities of $205.8 million in the first nine months of 2014, compared with $160.4 million in the first nine months of 2013. The improved cash flows were due primarily to $14.5 million in DOE Damages proceeds in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of $108.3 million in Pension Plan cash contributions in the first nine months 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 changes in working capital amounts, income tax payments of $9 million in the first nine months of 2014, compared with income tax refunds of $8.7 million in the first nine months 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 in the statements of income for WMECO for the nine months ended September 30, 2014 and 2013 included in this Quarterly Report on Form 10-Q:


			For the Nine Months Ended September 30,
							Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent
Operating Revenues			$	363.8	$	361.8	$	2.0	0.6	%
Operating Expenses:
	Purchased Power and Transmission			131.0		111.1		19.9	17.9
	Operations and Maintenance			67.1		70.2		(3.1)	(4.4)
	Depreciation			31.1		27.7		3.4	12.3
	Amortization of Regulatory Liabilities, Net			(7.8)		(0.6)		(7.2)	(a)
	Amortization of Rate Reduction Bonds			-		7.8		(7.8)	(100.0)
	Energy Efficiency Programs			33.1		28.5		4.6	16.1
	Taxes Other Than Income Taxes			25.7		20.2		5.5	27.2
		Total Operating Expenses		280.2		264.9		15.3	5.8
Operating Income				83.6		96.9		(13.3)	(13.7)
Interest Expense				18.9		18.8		0.1	0.5
Other Income, Net				1.7		2.3		(0.6)	(26.1)
Income Before Income Tax Expense				66.4		80.4		(14.0)	(17.4)
Income Tax Expense				26.6		30.4		(3.8)	(12.5)
Net Income			$	39.8	$	50.0	$	(10.2)	(20.4)	%

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

Operating Revenues
WMECO's retail sales volumes were as follows:
			For the Nine Months Ended September 30,
			2014		2013		Decrease		Percent
Retail Sales Volumes in GWh				2,721		2,786		(65)	(2.3)	%

WMECO's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to 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. There was also a $3.9 million increase in revenues that impacts earnings due to the reversal of a previously established wholesale billing adjustment. Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints. 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. Additionally, transition cost recovery revenues decreased due to the refund to customers of proceeds received from the Yankee Companies resulting from the spent nuclear fuel litigation. 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 expense includes costs associated with purchasing electricity on behalf of WMECO's customers. These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to an increase in purchased power due primarily to higher average supply prices and increased load as a result of customers returning to basic service from third party suppliers ($10.7 million) and an increase in transmission costs as a result of an increase in the retail transmission cost deferral ($9.2 million), which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, driven by a $3.1 million decrease in tracked costs, which have no earnings impact, which was primarily attributable to lower labor and other employee-related costs, including pension costs. Costs that impact earnings were flat for the nine months ended September 30, 2014, as compared to the same period in 2013.

Amortization of Regulatory Liabilities, Net, reflects a decrease in the recovery of transition costs primarily due to the refund of the DOE proceeds to customers for the nine months ended September 30, 2014, as compared to the same period in 2013. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.

Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2014, as compared to same period in 2013, due to the maturity of the RRBs in June 2013.

Energy Efficiency Programs, which are tracked costs, increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU.

Taxes Other Than Income Taxes increased for the nine months ended September 30, 2014, as compared to the same period 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.

Income Tax Expense decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower pre-tax earnings ($4.9 million), partially offset by various other tax impacts ($1.1 million).

EARNINGS SUMMARY

For the nine months ended September 30, 2014, WMECO's earnings decreased, as compared to the same period in 2013, due primarily to the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($3.7 million increase), higher depreciation expense and higher property tax expense. Partially offsetting these unfavorable earnings impacts were the reversal of a previously established wholesale billing adjustment and an increase in generation earnings.

LIQUIDITY

WMECO had cash flows provided by operating activities of $120.6 million in the first nine months of 2014, compared with $170.1 million in the first nine months of 2013. The decrease in operating cash flows was due primarily to income tax payments of $26.5 million in the first nine months of 2014, compared with income tax payments of $16.9 million in the first nine months of 2013, changes in working capital items, 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 $18.9 million in DOE Damages proceeds received in 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.

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

Evaluation of Disclosure 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 September 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.

Changes in Internal Control over Financial Reporting

During the third quarter of 2014, we implemented a new general ledger system resulting in a material change in internal controls over financial reporting. This new system, which went live effective August 1, 2014, standardized the financial systems for the merged companies and allows for a common set of accounting processes, practices and data structures across all operating companies. Pre-implementation testing and post-implementation reviews were conducted by management to ensure that internal controls surrounding the system implementation process, the applications, and the closing process were properly designed to prevent material financial statement errors. Such procedures included the review of required documents, user acceptance testing, change management procedures, access controls, data migration strategies and reconciliations, application interface testing and other standard application controls.

Except as described above, there have been no other changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended September 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)
July 1 – July 31, 2014	-	$	-	-	-
August 1 – August 31, 2014	34,452		45.37	-	-
September 1 – September 30, 2014	5,248		45.37	-	-
Total	39,700	$	45.37	-	-

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 November 7, 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 November 7, 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 November 7, 2014

	Listing of Exhibits (CL&P)

*	3.1	By-laws of CL&P, amended and restated as in effect September 29, 2014 (Exhibit 3.1, CL&P Current Report on Form 8-K filed October 2, 2014, File No. 000-00404)

*	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 Werner J. Schweiger, 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 November 7, 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 November 7, 2014

	32	Certification of Werner J. Schweiger, 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 November 7, 2014

	Listing of Exhibits (NSTAR Electric)

*	3.1	By-laws of NSTAR Electric, amended and restated as in effect September 29, 2014 (Exhibit 3.1, NSTAR Electric Company Current Report on Form 8-K filed October 2, 2014, File No. 001-02301)

	12	Ratio of Earnings to Fixed Charges

	31	Certification of Werner J. Schweiger, 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 November 7, 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 November 7, 2014

	32	Certification of Werner J. Schweiger, 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 November 7, 2014


	Listing of Exhibits (PSNH)

	3.1	By-laws of PSNH, amended and restated as in effect September 29, 2014

*	4.1	Twenty-First Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of October 1, 2014 (Exhibit 4.1, PSNH Current Report on Form 8-K filed October 17, 2014, File No. 001-06392)

	12	Ratio of Earnings to Fixed Charges

	31	Certification of Werner J. Schweiger, 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 November 7, 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 November 7, 2014

	32	Certification of Werner J. Schweiger, 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 November 7, 2014

	Listing of Exhibits (WMECO)

	3.1	By-laws of WMECO, amended and restated as in effect September 29, 2014

	12	Ratio of Earnings to Fixed Charges

	31	Certification of Werner J. Schweiger, 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 November 7, 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 November 7, 2014

	32	Certification of Werner J. Schweiger, 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 November 7, 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

November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE






	THE CONNECTICUT LIGHT AND POWER COMPANY

November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE






	NSTAR ELECTRIC COMPANY

November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE






	PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE






	WESTERN MASSACHUSETTS ELECTRIC COMPANY

November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer